36920 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 9 and 98 

[EPA–HQ–OAR–2019–0424; FRL–7230–02– 

OAR] 

RIN 2060–AU35 

Revisions and Confidentiality 

Determinations for Data Elements 

Under the Greenhouse Gas Reporting 

Rule 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing to amend 

specific provisions in the Greenhouse 

Gas Reporting Rule to improve the 

quality and consistency of the data 

collected under the rule, streamline and 

improve implementation, and clarify or 

propose minor updates to certain 

provisions that have been the subject of 

questions from reporting entities. These 

proposed changes include revisions to 

improve the existing calculation, 

recordkeeping, and reporting 

requirements by incorporating updates 

to existing emissions estimation 

methodologies and providing for 

collection of additional data to 

understand new source categories or 

new emission sources for specific 

sectors. The proposed changes would 

improve understanding of the sectorspecific processes or other factors that 

influence greenhouse gas emissions 

rates, improve verification of collected 

data, and complement or inform other 

EPA programs. The EPA is also 

proposing revisions that would improve 

implementation of the Greenhouse Gas 

Reporting Rule such as updates to 

applicability estimation methodologies, 

providing flexibility for or simplifying 

calculation and monitoring 

methodologies, streamlining 

recordkeeping and reporting, and other 

minor technical corrections or 

clarifications. This action also proposes 

to establish and amend confidentiality 

determinations for the reporting of 

certain data elements to be added or 

substantially revised in these proposed 

amendments. Further, this action 

includes a request for comment to 

solicit information that may aid in 

potential future revisions to the 

Greenhouse Gas Reporting Rule. 

DATES:

Comments. Comments must be 

received on or before August 22, 2022. 

Under the Paperwork Reduction Act 

(PRA), comments on the information 

collection provisions are best assured of 

consideration if the Office of 

Management and Budget (OMB) 

receives a copy of your comments on or 

before August 22, 2022. 

Public hearing. The EPA does not 

plan to conduct a public hearing unless 

requested. If anyone contacts us 

requesting a public hearing on or before 

June 27, 2022, we will hold a virtual 

public hearing. See SUPPLEMENTARY

INFORMATION for information on 

requesting and registering for a public 

hearing. 

ADDRESSES:

Comments. You may submit your 

comments, identified by Docket Id. No. 

EPA–HQ–OAR–2019–0424, by any of 

the following methods: 

Federal eRulemaking Portal: https://

www.regulations.gov (our preferred 

method). Follow the online instructions 

for submitting comments. 

Mail: U.S. Environmental Protection 

Agency, EPA Docket Center, Air and 

Radiation Docket, Mail Code 28221T, 

1200 Pennsylvania Avenue NW, 

Washington, DC 20460. 

Hand Delivery or Courier (by 

scheduled appointment only): EPA 

Docket Center, WJC West Building, 

Room 3334, 1301 Constitution Avenue 

NW, Washington, DC 20004. The Docket 

Center’s hours of operations are 8:30 

a.m.–4:30 p.m., Monday–Friday (except

federal holidays).

Instructions: All submissions received 

must include the Docket Id. No. for this 

proposed rulemaking. Comments 

received may be posted without change 

to https://www.regulations.gov/, 

including any personal information 

provided. Out of an abundance of 

caution for members of the public and 

our staff, the EPA Docket Center and 

Reading Room are closed to the public, 

with limited exceptions, to reduce the 

risk of transmitting Coronavirus 2019 

(COVID–19). Our Docket Center staff 

will continue to provide remote 

customer service via email, phone, and 

webform. We encourage the public to 

submit comments via https://

www.regulations.gov/ or email, as there 

may be a delay in processing mail and 

faxes. Hand deliveries and couriers may 

be received by scheduled appointment 

only. For further information on EPA 

Docket Center services and the current 

status, please visit us online at https:// 

www.epa.gov/dockets. 

Once submitted, comments cannot be 

edited or withdrawn. The EPA may 

publish any comment received to its 

public docket. Do not submit 

electronically any information you 

consider to be confidential business 

information (CBI) or other information 

whose disclosure is restricted by statute. 

Multimedia submissions (audio, video, 

etc.) must be accompanied by a written 

comment. The written comment is 

considered the official comment and 

should include discussion of all points 

you wish to make. The EPA will 

generally not consider comments or 

comment contents located outside of the 

primary submission (i.e., on the web, 

cloud, or other file sharing system). For 

additional submission methods, the full 

EPA public comment policy, 

information about CBI or multimedia 

submissions, and general guidance on 

making effective comments, please visit 

https://www.epa.gov/dockets/ 

commenting-epa-dockets. 

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: GHGReporting@epa.gov. 

For technical information, please go to 

the Greenhouse Gas Reporting Program 

(GHGRP) website, https://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 proposal will 

also be available through the WWW. 

Following the Administrator’s signature, 

a copy of this proposed rule will be 

posted on the EPA’s GHGRP website at 

https://www.epa.gov/ghgreporting. 

SUPPLEMENTARY INFORMATION: 

Participation in virtual public 

hearing. Please note that the EPA is 

deviating from its typical approach for 

public hearings because the President 

has declared a national emergency. Due 

to the current Centers for Disease 

Control and Prevention (CDC) 

recommendations, as well as state and 

local orders for social distancing to limit 

the spread of COVID–19, the EPA 

cannot hold in-person public meetings 

at this time. 

To request a hearing, please contact 

the person listed in the following FOR

FURTHER INFORMATION CONTACT section 

by June 27, 2022. If requested, the 

virtual hearing will be held on July 6, 

2022. The hearing will convene at 9 a.m. 

Eastern Time (ET) and will conclude at 

3 p.m. ET. The EPA may close the 

hearing 15 minutes after the last preregistered speaker has testified if there 

are no additional speakers. The EPA 

will provide further information about 

the hearing on its website (https://

www.epa.gov/ghgreporting) if a hearing 

is requested. 


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Upon publication of this document in 

the Federal Register (FR), the EPA will 

begin pre-registering speakers for the 

hearing, if a hearing is requested. To 

register to speak at the virtual hearing, 

please use the online registration form 

available at https://www.epa.gov/ 

ghgreporting. If you have questions 

regarding registration, consult the 

person listed in the preceding FOR

FURTHER INFORMATION CONTACT section. 

The last day to pre-register to speak at 

the hearing will be July 5, 2022. Prior 

to the hearing, the EPA will post a 

general agenda that will list preregistered speakers in approximate 

order at: https://www.epa.gov/ 

ghgreporting. 

The EPA will make every effort to 

follow the schedule as closely as 

possible on the day of the hearing; 

however, please plan for the hearings to 

run either ahead of schedule or behind 

schedule. 

Each commenter will have 5 minutes 

to provide oral testimony. The EPA 

encourages commenters to provide the 

EPA with a copy of their oral testimony 

electronically (via email) by emailing it 

to GHGReporting@epa.gov. The EPA 

also recommends submitting the text of 

your oral testimony as written 

comments to the rulemaking docket. 

The EPA may ask clarifying questions 

during the oral presentations but will 

not respond to the presentations at that 

time. Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as oral testimony 

and supporting information presented at 

the public hearing. 

Please note that any updates made to 

any aspect of the hearing will be posted 

online at https://www.epa.gov/ 

ghgreporting. While the EPA expects the 

hearing to go forward as set forth above, 

please monitor our website or contact us 

by email at GHGReporting@epa.gov to 

determine if there are any updates. The 

EPA does not intend to publish a 

document in the Federal Register 

announcing updates. 

If you require the services of a 

translator or a special accommodation 

such as audio description, please preregister for the hearing with the public 

hearing team and describe your needs 

by June 28, 2022. The EPA may not be 

able to arrange accommodations without 

advanced notice. 

Regulated entities. These proposed 

revisions would affect certain entities 

that must submit annual greenhouse gas 

(GHG) reports under the GHGRP (40 

CFR part 98). These are proposed 

amendments to existing regulations. If 

finalized, these amended regulations 

would also affect owners or operators of 

certain 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

Category NAICS Examples of affected facilities 

General Stationary Fuel Combustion 

Sources.

.............................. Facilities operating boilers, process heaters, incinerators, turbines, and internal 

combustion engines. 

211 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. 

Ammonia Manufacturing .......................... 325311 Anhydrous and aqueous ammonia manufacturing facilities. 

Cement Production .................................. 327310 Portland cement manufacturing plants. 

Electronics Manufacturing ........................ 334111 Microcomputers manufacturing facilities. 

334413 Semiconductor, photovoltaic (PV) (solid-state) device manufacturing facilities. 

334419 Liquid crystal display (LCD) unit screens manufacturing facilities; 

Microelectromechanical (MEMS) manufacturing facilities. 

Ferroalloy Production ............................... 331110 Ferroalloys manufacturing facilities. 

Fluorinated Greenhouse Gas Production 325120 Industrial gases manufacturing facilities. 

Glass Production ...................................... 327211 Flat glass manufacturing facilities. 

327213 Glass container manufacturing facilities. 

327212 Other pressed and blown glass and glassware manufacturing facilities. 

Hydrogen Production ............................... 325120 Hydrogen manufacturing facilities. 

Iron and Steel Production ........................ 333110 Integrated iron and steel mills, steel companies, sinter plants, blast furnaces, 

basic oxygen process furnace (BOPF) shops. 

Lime Manufacturing .................................. 327410 Calcium oxide, calcium hydroxide, dolomitic hydrates manufacturing facilities. 

Miscellaneous Uses of Carbonate ........... Facilities included elsewhere. 

Petroleum and Natural Gas Systems ...... 486210 Pipeline transportation of natural gas. 

221210 Natural gas distribution facilities. 

211120 Crude petroleum extraction. 

211130 Natural gas extraction. 

Petrochemical Production ........................ 325110 Ethylene dichloride manufacturing facilities. 

325199 Acrylonitrile, ethylene oxide, methanol manufacturing facilities. 

325110 Ethylene manufacturing facilities. 

325180 Other basic inorganic chemical manufacturing. 

Petroleum Refineries ................................ 324110 Petroleum refineries. 

Silicon Carbide Production ....................... 327910 Silicon carbide abrasives manufacturing facilities. 

Electrical Equipment Use ......................... 221121 Electric bulk power transmission and control facilities. 


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TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued 

Category NAICS Examples of affected facilities 

Underground Coal Mines ......................... 212113 Underground anthracite coal mining operations. 

212112 Underground bituminous coal mining operations. 

Zinc Production ........................................ 331419 Primary zinc refining facilities. 

331492 Zinc dust recycling facilities, recovering from scrap and/or alloying purchased 

metals. 

311411 Frozen fruit, juice, and vegetable manufacturing facilities. 

311421 Fruit and vegetable canning facilities. 

Municipal Solid Waste Landfills ............... 562212 Solid waste landfills. 

221320 Sewage treatment facilities. 

Suppliers of Coal-based Liquid Fuels ...... 211130 Coal liquefaction at mine sites. 

Suppliers of Natural Gas and Natural 

Gas Liquids.

221210 Natural gas distribution facilities. 

211112 Natural gas liquid extraction facilities. 

Suppliers of Petroleum Products ............. 324110 Petroleum refineries. 

Suppliers of Carbon Dioxide .................... 325120 Industrial gas manufacturing facilities. 

Suppliers of Industrial Greenhouse 

Gases.

325120 Industrial greenhouse gas manufacturing facilities. 

Electrical Equipment Manufacture or Refurbishment.33531 Power transmission and distribution switchgear and specialty transformers manufacturing facilities. 

Carbon Dioxide Enhanced Oil Recovery 

Projects.

211 Oil and gas extraction projects using carbon dioxide enhanced oil recovery. 

Calcium Carbide Production .................... 325180 Other basic inorganic chemical manufacturing. 

Coke Calcining ......................................... 324199 All other petroleum and coal products manufacturing. 

Glyoxal, Glyoxylic Acid, and Caprolactam 

Production.

325199 All other basic organic chemical manufacturing. 

Ceramics Manufacturing .......................... 327110 Pottery, ceramics, and plumbing fixture manufacturing. 

327120 Clay building material and refractories manufacturing. 

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 

proposed action. Other types of facilities 

than those listed in the table could also 

be subject to reporting requirements. To 

determine whether you would be 

affected by this proposed 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. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

AGA American Gas Association 

AIM American Innovation and 

Manufacturing Act of 2020 

AMLD Advanced Mobile Leak Detection 

ANOVA analysis of variance 

ANSI American National Standards 

Institute 

API American Petroleum Institute 

ASTM American Society for Testing and 

Materials 

BAMM best available monitoring methods 

BEF by-product emission factor 

BOEM Bureau of Ocean Energy 

Management 

BOPF basic oxygen process furnace 

C&D construction and demolition 

CAA Clean Air Act 

CARB California Air Resources Board 

CBI confidential business information 

CBP U.S. Customs and Border Protection 

CCUS carbon capture, utilization, and 

sequestration 

CDA clean dry air 

CDC Centers for Disease Control and 

Prevention 

CEMS continuous emission monitoring 

system 

CFR Code of Federal Regulations 

CGA cylinder gas audit 

CF4 perfluoromethane 

CH4 methane 

CKD cement kiln dust 

CO2 carbon dioxide 

CO2e carbon dioxide equivalent 

CO carbon monoxide 

COF2 carbonic difluoride 

COVID–19 Coronavirus 2019 

CSA CSA Group 

CVD chemical vapor deposition 

DAC direct air capture 

DCU delayed coking unit 

DOC degradable organic carbon 

DOT Department of Transportation 

DRE destruction or removal efficiency 

e-GGRT electronic Greenhouse Gas 

Reporting Tool 

EAF electric arc furnace 

EDC ethylene dichloride 

EF emission factor 

EG emission guidelines 

EIA Energy Information Administration 

EOR enhanced oil recovery 

EPA U.S. Environmental Protection Agency 

EREF Environmental Research and 

Education Foundation 

ET Eastern time 

FAQ frequently asked question 

FR Federal Register 

F–GHG fluorinated greenhouse gas 

F–HTFs fluorinated heat transfer fluids 

FTIR Fourier Transform Infrared 

GCS gas collection system 

GHG greenhouse gas 

GHGRP Greenhouse Gas Reporting Program 

GIE gas-insulated equipment 

GIS geographic information systems 

GOR gas-to-oil ratio 

GRI Gas Research Institute 

GWP global warming potential 

HCFC hydrochlorofluorocarbons 

HFC hydrofluorocarbons 

HHV high heating value 

HTS Harmonized Tariff System 

HVAE high voltage anode effect 

IAI International Aluminium Institute 

ICR Information Collection Request 

IPCC Intergovernmental Panel on Climate 

Change 

IRC Internal Revenue Code 

IRS Internal Revenue Service 

ISBN International Standard Book Number 

ISO International Standards Organization 

IVT Inputs Verification Tool 

k first order decay rate 

kg kilograms 

LCA life cycle analysis 

LCD liquid crystal display 

LDC local distribution company 

LNG liquified natural gas 

LVAE low voltage anode effect 

MCF moisture correction factor 

MDEA methyl diethanolamine 

MEA monoethanolamine 

MEMS microelectromechanical systems 

mmBtu/hr million British thermal units per 

hour 

MMscf million standard cubic feet 

MRV monitoring, reporting, and 

verification plan 

MSHA Mine Safety and Health 

Administration 

MSW municipal solid waste 

mtCO2e metric tons carbon dioxide 

equivalent 


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N2O nitrous oxide 

NAICS North American Industry 

Classification System 

NGLs natural gas liquids 

NSPS New Source Performance Standards 

OAR Office of Air and Radiation 

OEM original equipment manufacturer 

OGI optical gas imaging 

OMB Office of Management and Budget 

OMP operations management plan 

PCA Portland Cement Association 

PFC perfluorocarbon 

PRA Paperwork Reduction Act 

ppmv parts per million by volume 

PV photovoltaic 

QA/QC quality assurance/quality control 

QMS Quadrupole Mass Spectroscopy 

RFA Regulatory Flexibility Act 

RMA Rubber Manufacturers Association 

RPC remote plasma cleaning 

RY reporting year 

scfh standard cubic feet per hour 

SF6 sulfur hexafluoride 

SIA Semiconductor Industry Association 

SIC Standard Industrial Classification 

System 

SSM startup, shutdown, and malfunction 

TBD to be determined 

TFI The Fertilizer Institute 

TSCA Toxic Substances Control Act 

TSD technical support document 

UIC underground injection control 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 

1995 

USGS U.S. Geological Survey 

USTMA U.S. Tire Manufacturers 

Association 

VCM vinyl chloride monomer 

VOC volatile organic compound 

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 Proposed Rule 

D. Legal Authority 

II. Overview and Rationale for Proposed 

Amendments to 40 CFR Part 98 and 40 

CFR Part 9 

A. Revisions To Improve the Quality of 

Data Collected Under 40 CFR Part 98 and 

Other Minor Revisions or Clarifications 

B. Revisions To Streamline and Improve 

Implementation of 40 CFR Part 98 

C. Revisions to 40 CFR Part 9 

III. Proposed Amendments to 40 CFR Part 98 

A. Subpart A—General Provisions 

B. Subpart C—General Stationary Fuel 

Combustion Sources 

C. Subpart G—Ammonia Manufacturing 

D. Subpart H—Cement Production 

E. Subpart I—Electronics Manufacturing 

F. Subpart N—Glass Production 

G. Subpart P—Hydrogen Production 

H. Subpart Q—Iron and Steel Production 

I. Subpart S—Lime Manufacturing 

J. Subpart W—Petroleum and Natural Gas 

Systems 

K. Subpart X—Petrochemical Production 

L. Subpart Y—Petroleum Refineries 

M. Subpart BB—Silicon Carbide 

Production 

N. Subpart DD—Electrical Transmission 

and Distribution Equipment Use 

O. Subpart FF—Underground Coal Mines 

P. Subpart GG—Zinc Production 

Q. Subpart HH—Municipal Solid Waste 

Landfills 

R. Subpart NN—Suppliers of Natural Gas 

and Natural Gas Liquids 

S. Subpart OO—Suppliers of Industrial 

Greenhouse Gases 

T. Subpart PP—Suppliers of Carbon 

Dioxide 

U. Subpart SS—Electrical Equipment 

Manufacturers or Refurbishment 

V. Subpart UU—Injection of Carbon 

Dioxide 

W. Subpart VV—Geologic Sequestration of 

Carbon Dioxide With Enhanced Oil 

Recovery Using ISO 27916 

IV. Additional Requests for Comment 

A. Energy Consumption 

B. Ceramics Production 

C. Calcium Carbide Production 

D. Glyoxal, Glyoxylic Acid, and 

Caprolactam Production 

E. Coke Calcining 

F. CO2 Utilization 

G. Aluminum Production 

V. Schedule for the Proposed Amendments 

VI. Proposed Confidentiality Determinations 

for Certain Data Reporting Elements 

A. Overview and Background 

B. Proposed Confidentiality 

Determinations and Emissions Data 

Designations 

C. Proposed Reporting Determinations for 

Inputs to Emissions Equations 

D. Proposed Revisions to Confidentiality 

Determinations for Existing 40 CFR part 

98 Data Elements Affected by the AIM 

Implementation Rule 

E. Request for Comments on Proposed 

Category Assignments, Confidentiality 

Determinations, or Determinations of 

Inputs To Be Reported 

VII. Impacts of the Proposed Amendments 

VIII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

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 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Determination Under CAA Section 

307(d) 

I. Background 

A. How is this preamble organized? 

The first section of this preamble 

contains background information 

regarding the origin of the proposed 

amendments. This section also 

discusses the EPA’s legal authority 

under the Clean Air Act (CAA) to 

promulgate (including subsequent 

amendments to) the Greenhouse Gas 

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 required by 

these amendments or for existing data 

elements for which a confidentiality 

determination has not previously been 

proposed. Section II of this preamble 

describes the types of amendments 

included in this proposed rulemaking 

and includes the rationale for each type 

of proposed change. Section III of this 

preamble is organized by part 98 

subpart and contains detailed 

information on the proposed revisions 

to part 98 and the rationale for the 

proposed amendments in each section. 

Section IV of this preamble discusses 

additional requests for comments 

related to potentially expanding or 

adding new source categories and other 

potential future amendments to the 

GHG Reporting Rule. Section V of this 

preamble discusses when the proposed 

revisions to part 98 would apply to 

reporters. Section VI of this preamble 

discusses the proposed 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 a 

determination has not been previously 

established. Section VII of this preamble 

discusses the impacts of the proposed 

amendments. Section VIII of this 

preamble describes the statutory and 

executive order requirements applicable 

to this action. 

B. Executive Summary 

The EPA is proposing amendments to 

part 98 to implement improvements to 

the GHGRP. After more than 10 years of 

implementation of the program, the EPA 

has assessed the data collected, 

emissions, and trends established from 

annual reports in each industrial sector 

required to report. In this review, the 

EPA has evaluated the requirements of 

the GHGRP to identify areas of 

improvement, such as where the rule 

may be modified to reflect the EPA’s 

current understanding of United States 

(U.S.) GHG emission trends, or to 

improve data collection and reporting 

where additional data may be necessary 

to better understand emissions from 

specific sectors or inform future policy 

decisions. The EPA has subsequently 

identified improvements to the 

calculation, monitoring, and reporting 


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1Consolidated Appropriations Act, 2008, Public 

Law 110–161, 121 Stat. 1844, 2128. See https://

www.congress.gov/110/plaws/publ161/PLAW110publ161.pdf (accessed September 7, 2021). 

requirements that would incorporate 

new data or updated scientific 

knowledge; reflect new emissions 

sources; improve analysis and 

verification of collected data; provide 

additional data to complement or 

inform other EPA programs; or 

streamline calculation, monitoring, or 

reporting to provide flexibility or 

increase the efficiency of data 

collection. 

The proposed amendments include 

improvements to requirements that 

would enhance the quality of the data 

collected, clarify elements of the rule, 

and streamlining changes. The types of 

proposed amendments that would 

improve the quality of the data collected 

under the rule include revisions to 

update 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; 

providing for collection of additional 

data to understand new source 

categories or new emission sources for 

specific sectors; additions or 

modifications to reporting requirements 

in order to eliminate data gaps and 

improve verification of emissions 

estimates; revisions that address prior 

commenter concerns or clarify 

requirements, and editorial corrections 

that would improve the public’s 

understanding of the rule. 

The types of streamlining changes 

that the EPA is proposing include 

revisions to applicability for certain 

industry sectors to account for changes 

in usage of certain GHGs or 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 

provide new insights or knowledge of 

the industry sector, emissions, or trends 

at this time. 

This action also includes a request for 

comment related to potentially 

expanding existing categories or 

including additional new source 

categories to the Greenhouse Gas 

Reporting Rule. In these cases, the EPA 

is seeking additional information to 

better inform our consideration of 

proposing these new source categories 

to the GHGRP. Therefore, the EPA is 

specifically requesting comment related 

to the potential expanded or new source 

categories described in this section. The 

EPA is also requesting comment on 

potential future amendments to add 

new calculation, monitoring, and 

reporting requirements for the 

aluminum production source category. 

If the Agency becomes comfortable that 

the information available is sufficient to 

support a rule revision, the EPA may 

consider undertaking a future action to 

revise or add source categories or to 

incorporate updated calculation and 

reporting requirements. 

Further, this action includes a 

proposal to update 40 CFR part 9 in 

accordance with the publication 

requirements of the PRA to include the 

OMB control number issued under the 

PRA for the information collection 

request (ICR) for the GHGRP. 

Finally, this action proposes to 

establish and/or revise confidentiality 

determinations for the reporting of 

certain data elements added or revised 

in these proposed amendments, and for 

certain existing data elements for which 

no confidentiality determination has 

been previously proposed, or for which 

we are proposing to amend a previously 

established confidentiality 

determination. 

Most of the changes that are proposed 

are not anticipated to significantly 

increase the recordkeeping and 

reporting burden associated with the 

GHGRP. The proposed changes are 

anticipated to improve the quality of the 

data reported under the program. Some 

of the proposed revisions could 

potentially increase burden in cases 

where the proposed amendments add or 

revise reporting requirements. The 

estimated incremental costs include an 

average burden of $1,424,775 per year 

beginning in reporting year (RY) 2023. 

The EPA anticipates that the proposed 

changes may take effect on January 1, 

2023 and would apply beginning with 

reports submitted for RY2023, which are 

required to be submitted to the EPA by 

April 1, 2024. 

C. Background on This Proposed Rule 

The GHG Reporting Rule was 

published in the Federal Register (FR) 

on October 30, 2009 (74 FR 56260) 

(hereafter referred to as the 2009 Final 

Rule). The 2009 Final Rule became 

effective on December 29, 2009 and 

requires reporting of GHGs from various 

facilities and suppliers, consistent with 

the 2008 Consolidated Appropriations 

Act.1 The EPA issued additional rules in 

2010 finalizing the requirements for 

subpart T (Magnesium Production), 

subpart FF (Underground Coal Mines), 

subpart II (Industrial Wastewater 

Treatment), and subpart TT (Industrial 

Waste Landfills) (75 FR 39736, July 12, 

2010); subpart W (Petroleum and 

Natural Gas Systems) (75 FR 74458, 

November 30, 2010); subpart I 

(Electronics Manufacturing), subpart L 

(Fluorinated Gas Production), subpart 

DD (Electrical Transmission and 

Distribution Equipment Use), subpart 

QQ (Importers and Exporters of 

Fluorinated GHGs Contained in PreCharged Equipment or Closed-Cell 

Foams), and subpart SS (Electrical 

Equipment Manufacture or 

Refurbishment) (75 FR 74774, December 

1, 2010); and subpart RR (Geologic 

Sequestration of Carbon Dioxide) and 

subpart UU (Injection of Carbon 

Dioxide) (75 FR 75060, December 1, 

2010). Following the promulgation of 

these subparts, the EPA finalized several 

technical and clarifying amendments to 

these and other subparts under the 

GHGRP (75 FR 79092, December 17, 

2010; 76 FR 22825, April 25, 2011; 76 

FR 36339, June 22, 2011; 76 FR 59533, 

September 27, 2011; 76 FR 59542, 

September 27, 2011; 76 FR 73866, 

November 29, 2011; 76 FR 80554, 

December 23, 2011; 77 FR 10373, 

February 22, 2012; 77 FR 48072, August 

13, 2012; 77 FR 51477, August 24, 2012; 

78 FR 25392, May 1, 2013; 78 FR 68162, 

November 13, 2013; 78 FR 71904, 

November 29, 2013; 79 FR 63750, 

October 24, 2014; 79 FR 70352, 

November 25, 2014; 79 FR 73750, 

December 11, 2014; 80 FR 64262, 

October 22, 2015; and 81 FR 86490, 

November 30, 2016). The amendments 

generally added or revised requirements 

in the existing subparts of part 98, 

including revisions that were intended 

to improve clarity and consistency 

across the calculation, monitoring, and 

data reporting requirements. The EPA 

finalized additional amendments (81 FR 

89188, December 6, 2016) to streamline 

implementation of the rule, to improve 

the quality and consistency of the data 

collected under the rule, and to clarify 

or provide updates to certain provisions 

that have been the subject of questions 

from reporting entities. The EPA is 

proposing additional amendments and 

requesting comment in a continuation of 

the effort to improve the GHGRP. 

D. Legal Authority 

The EPA is proposing these rule 

amendments under its existing CAA 

authority provided in CAA section 114. 

As stated in the preamble to the 2009 

Final Rule (74 FR 56260), CAA section 

114(a)(1) provides the EPA broad 

authority to require the information 


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proposed to be gathered by this rule 

because such data would inform and are 

relevant to the EPA’s carrying out of a 

wide variety of CAA provisions. See the 

preambles to the proposed GHG 

Reporting Rule (74 FR 16606, October 

10, 2009) and the 2009 Final Rule for 

further information. 

II. Overview and Rationale for 

Proposed Amendments to 40 CFR Part 

98 and 40 CFR Part 9 

Since 2010, the GHGRP has been a 

reliable and high-quality source of GHG 

data. The data collected under 40 CFR 

part 98 is used to inform the EPA’s 

understanding of the relative emissions 

and distribution of emissions from 

specific industries, the factors that 

influence GHG emission rates, and to 

inform policy options and potential 

regulations. The data published under 

the GHGRP also serves to enable key 

stakeholders to understand, track, and 

compare greenhouse gas emissions and 

identify and take action on emission 

reduction opportunities. Further, the 

data collected under the GHGRP has 

also been used to inform other 

regulations, for example, proposed New 

Source Performance Standards (NSPS) 

and Emission Guidelines for the oil and 

gas industry and for municipal solid 

waste (MSW) landfills under 40 CFR 

part 60. 

Throughout the life of the GHGRP, the 

EPA has made several improvements to 

the rule to address data gaps, reflect 

updates to scientific information, or to 

incorporate improvements to 

calculation, monitoring, or 

measurement methodologies. For 

example, in 2013, the EPA finalized 

technical amendments including 

changes to applicability, improvements 

to calculation methods, and updated 

reporting requirements, as well as 

amendments to incorporate new data 

from the Intergovernmental Panel on 

Climate Change (IPCC) on estimated 

global warming potentials (GWPs) (78 

FR 71904, November 29, 2013). More 

recently, the EPA finalized edits to the 

petroleum and natural gas systems 

source category to address potential 

gaps in coverage, improve methods, and 

ensure high quality data reporting (81 

FR 86490, November 30, 2016). The 

EPA last updated the GHGRP in 2016, 

when it implemented revisions to 

streamline and improve implementation 

of the rule and to improve the quality 

of the data collected, including 

expanding monitoring and reporting 

requirements that were necessary to 

improve verification and served to 

improve the accuracy of the data used 

to inform the Inventory of U.S. 

Greenhouse Gas Emissions and Sinks 

(hereafter referred to as the ‘‘U.S. GHG 

Inventory’’) (81 FR 89188, December 9, 

2016). 

The EPA has also continuously 

conducted outreach to stakeholders 

through various means, including 

responding to questions from reporters, 

engaging through compliance assistance 

webinars, soliciting feedback via a 

public testing process, interacting with 

reporters during the verification of 

submitted data, and soliciting comments 

during rulemakings. Thus, the EPA has 

subsequently identified, proposed, and 

finalized several technical and 

clarifying amendments to various 

subparts under the GHGRP to enhance 

the quality of the data reported, improve 

our understanding of GHG emission 

sources and trends, and improve 

implementation, particularly where we 

have identified changes to industry 

processes, emissions trends, types of 

emissions sources, or new data or 

scientific knowledge that would allow 

us to better understand the quantity and 

distribution of U.S. GHG emissions. 

The EPA recently evaluated the 

requirements of the GHGRP to identify 

areas of improvement, such as where 

the rule may be modified to reflect the 

EPA’s current understanding of U.S. 

GHG emission trends, or to improve 

data collection and reporting where 

additional data may be necessary to 

better understand emissions from 

specific sectors or inform future policy 

decisions. The proposed amendments 

include improvements to the 

calculation, monitoring, and reporting 

requirements that would incorporate 

updates to existing emissions estimation 

methodologies; implement requirements 

to collect additional data to understand 

new source categories or new emission 

sources for specific sectors; improve the 

EPA’s understanding of the sectorspecific processes or other factors that 

influence GHG emission rates and 

improve verification of collected data; 

and provide additional data to 

complement or inform other EPA 

programs. We are also proposing 

revisions that clarify or update 

provisions that have been unclear. The 

proposed amendments include: 

• Amendments to update emission 

factors to incorporate new measurement 

data that more accurately reflects 

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; 

• Revisions to specific sectors to 

expand reporting to include new source 

categories or new emission sources, in 

order to improve the accuracy and 

completeness of the data provided by 

the GHGRP; 

• Adding or modifying reporting 

requirements to eliminate data gaps and 

improve verification of emissions 

estimates; and 

• Revisions that address prior 

commenter concerns or provide 

additional information for reporters to 

better or more fully understand their 

compliance obligations, that clarify 

requirements that reporters have 

previously found vague to ensure that 

accurate data are being collected, and 

editorial corrections or harmonizing 

changes that would improve the 

public’s understanding of the rule. 

The EPA is also soliciting additional 

comment on potentially expanding 

existing subparts or adding other new 

subparts to collect data for several new 

source categories, as well as requesting 

comment on potential future 

amendments to add new calculation, 

monitoring, and reporting requirements 

for the aluminum production source 

category, as discussed in section IV of 

this preamble. 

The EPA has also identified 

additional areas in the GHGRP where 

revisions to part 98 could be 

streamlined. Through this document, 

the EPA is proposing several 

amendments to revise specific 

provisions in part 98 that would 

streamline calculation, monitoring, or 

reporting to provide flexibility or 

increase the efficiency of data 

collection. The types of revisions we are 

proposing would 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 proposed 

revisions include: 

• Revisions to applicability for 

certain industry sectors without the 

25,000 metric tons carbon dioxide 

equivalent (mtCO2e) per year reporting 

threshold to account for changes in 

usage of certain GHGs, or where the 

current applicability estimation 

methodology may overestimate 

emissions; 

• Providing flexibility for and 

simplifying monitoring and calculation 

methods where further monitoring and 

data collection would 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 streamline reported 

data elements or recordkeeping where 

the current requirements are redundant 


jspears on DSK121TN23PROD with PROPOSALS2
36926 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

2 Intergovernmental Panel on Climate Change 

(IPCC). 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. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

or 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 

provide new insights or knowledge of 

the industry sector, emissions, or trends 

at this time. 

Sections II.A and II.B of this preamble 

describe the above changes in more 

detail and provide rationale for the 

changes included in each category. 

Additional details for the specific 

amendments proposed for each subpart 

are included in section III of this 

preamble. We are seeking public 

comment only on the proposed 

revisions and issues specifically 

identified in this document for the 

identified subparts. We expect to deem 

any comments received addressing 

other aspects of 40 CFR part 98 to be 

outside of the scope of this proposed 

rulemaking. 

Finally, we are also proposing 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 ICR for 40 CFR part 98. 

This amendment is described in section 

II.C of this preamble. 

A. Revisions To Improve the Quality of 

Data Collected Under 40 CFR Part 98 

and Other Minor Revisions or 

Clarifications 

The data collected under part 98 are 

used to inform the EPA’s understanding 

of the relative emissions and 

distribution of emissions from specific 

industries, the factors that influence 

GHG emission rates, and to inform 

policy options and potential regulations. 

Following several years of 

implementation and outreach, the EPA 

has identified certain areas of the rule 

where updates to emissions factors or 

other default factors; improvements to 

calculation methodologies; collection of 

additional data on GHG emissions, 

emissions sources, or end uses; 

additions or revisions to data elements 

or other reporting requirements; and 

other technical amendments, 

clarifications, and corrections would 

enhance the quality and accuracy of the 

data collected under the GHGRP. These 

proposed changes include consideration 

of comments raised by stakeholders in 

prior rulemakings that would more 

closely align rule requirements with the 

processes conducted at specific 

facilities, consideration of data gaps 

identified in collected data where 

additional data would improve 

verification of data reported to the 

GHGRP, and consideration of additional 

data needed to help better understand 

changing industry emission trends. 

Overall, these proposed changes would 

provide a more comprehensive, 

nationwide GHG emissions profile 

reflective of the origin and distribution 

of GHG emissions in the United States 

and would more accurately inform EPA 

policy options for potential regulatory 

or non-regulatory CAA programs. The 

EPA additionally uses the data from the 

GHGRP, which would include data from 

these proposed changes, to improve 

estimates used in the U.S. GHG 

Inventory. 

In some cases, we are proposing to 

redefine certain industry sectors to 

include additional GHGs not previously 

reported, or to add emissions 

estimations methodologies and include 

reporting of GHGs from newly identified 

sources of emissions in certain industry 

sectors, to better account for changes in 

industry emission trends. The proposed 

amendments reflect adjustments to the 

rule where we have identified changes 

in the type and scope of GHGs emitted 

or supplied, such as certain sectors that 

have implemented alternative 

equipment technology, switched to use 

of GHGs with a lower GWP, or that have 

implemented new end uses for GHGs 

that are emitted or supplied. In other 

cases, we have identified gaps in the 

current coverage of the GHGRP that 

leave out potentially significant 

emission sources, for example, large, 

atypical release events at oil and gas 

facilities such as wellhead leaks. The 

proposed amendments would also add a 

new source category that would provide 

additional data on amounts of CO2 that 

are geologically sequestered in 

association with enhanced oil recovery 

(EOR) operations. Many of the revisions 

proposed in this action would better 

capture the changing landscape of 

greenhouse gas emissions and provide 

for more complete coverage of U.S. GHG 

emission sources. Such changes are 

necessary for the EPA to continue to 

analyze the relative emissions and 

distribution of emissions from specific 

industries and to improve the overall 

quality of the data collected under the 

GHGRP. These changes would also 

complement other EPA regulations, 

such as NSPS and emission guidelines 

(EG) for the oil and gas industry and 

would also be used to inform and 

improve future policy decisions. 

The specific changes that we are 

proposing, as described in this section, 

are described in detail for each subpart 

in sections III.A through III.W of this 

preamble. 

1. Updates to Emission Factors To 

Improve Accuracy of Reported Data 

In order to improve the accuracy of 

the data collected under the GHGRP, we 

are proposing to revise emission factors 

where we have received improved 

measurement data or feedback from 

stakeholders. Some of the calculation 

methodologies provided in the GHGRP 

rely on the use of emission factors, and 

the use of emissions or default factors 

decreases the need for additional 

monitoring or measurements from 

individual facilities. The proposed rule 

includes revisions to emission factors in 

a number of source categories, where we 

have received or identified updated 

measurement data. For example, we are 

proposing several updates to the 

emission factors and default destruction 

and removal efficiency values in subpart 

I (Electronics Manufacturing). The 

proposed emission factors are based on 

review of newly submitted data from the 

2017 and 2020 technology assessment 

reports submitted 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’’).2 We are also 

proposing updates to the emission factor 

calculation methods that are used to 

calculate utilization and by-product 

emission rates submitted in the 

technology assessment report under 

subpart I, in order to ensure that 

emission factors are developed in a 

consistent manner across facilities and 

over time and to allow the EPA to 

compare emission factors across the 

industry and track trends in industry 

emission rates. 

In some cases, the proposed emission 

factors would improve reported data by 

better reflecting recent industry trends. 

For example, based on input from 

stakeholders, we are proposing updated 

emission factors for the modeling of 

methane (CH4) generation from waste 

disposed at landfills in subpart HH 

(Municipal Waste Landfills). The 

updated emission factors reflect an 

industry trend of increased disposal of 

inert materials that do not contribute to 

CH4 generation. The EPA received data 

from stakeholders in the waste industry 

following comments received during the 

expert and public review period for the 

U.S. GHG Inventory, which uses 

directly reported emissions values from 

subpart HH to estimate national CH4

emissions from MSW landfills 


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throughout the entire United States. The 

proposed change will update default 

factors and will result in more accurate 

estimates of landfill emissions and pose 

no additional reporting burden. 

We are also proposing to update the 

default biogenic fraction for tire 

combustion in subpart C (General 

Stationary Fuel Combustion) and the 

emission factors for natural gas 

pneumatic devices and for equipment 

leaks from natural gas distribution 

sources (including pipeline mains and 

services, below grade transmissiondistribution transfer stations, and below 

grade metering-regulating stations) and 

equipment at onshore petroleum and 

natural gas production and onshore 

petroleum and natural gas gathering and 

boosting facilities in subpart W 

(Petroleum and Natural Gas Systems). 

The proposed emission factors are more 

representative of GHG emissions 

sources and would improve the overall 

accuracy of the data collected under the 

GHGRP and would ultimately benefit 

stakeholders who rely on GHGRP data 

to understand the sources and 

magnitude of GHGs from specific 

facilities, as well as improve the quality 

of data used to inform future policy or 

regulation. 

2. Improvements To Existing Emissions 

Estimation Methodologies 

We are proposing several revisions to 

modify calculation equations to 

incorporate refinements to 

methodologies based on an improved 

understanding of emission sources. In 

some cases, we have become aware of 

discrepancies between assumptions in 

the current emission estimation 

methods and the processes or activities 

conducted at specific facilities, where 

the proposed revisions would reduce 

reporter errors. In other cases, we are 

proposing to revise the emissions 

estimation methodologies to incorporate 

recent studies on GHG emissions or 

formation that reflect updates to 

scientific understanding of GHG 

emissions sources. The proposed 

changes will improve the quality and 

accuracy of the data collected under the 

GHGRP, increase our understanding of 

the relative distribution of GHGs that 

are emitted, and better reflect GHG end 

uses or where GHGs are bound in 

products. 

For example, for subpart I, we are 

proposing several edits to the stack 

testing methodology, including adding 

new equations and a table of default 

weighting factors to calculate the 

fraction of fluorinated input gases and 

by-products exhausted from tools with 

abatement systems; revising equations 

that calculate the weighted average 

DREs for individual fluorinated 

greenhouse gases (F–GHGs) across 

process types; requiring that all stacks 

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 other subparts, including subparts 

G (Ammonia Manufacturing), P 

(Hydrogen Production), and S (Lime 

Manufacturing), we are proposing 

revisions to the calculation 

methodology to allow for subtraction of 

carbon dioxide (CO2) that is captured 

and bound in other products (e.g., urea 

or methanol) from calculated and 

reported emissions. The proposed 

changes, by removing the CO2 that is not 

directly emitted from these facilities 

from the calculation methodology, 

would provide a more accurate estimate 

of the direct sector emissions and would 

provide consistency in our approach 

across the GHGRP. 

For subpart Y (Petroleum Refineries), 

we are proposing to amend the 

calculation methodology for delayed 

coking units (DCUs), which uses a steam 

generation model to estimate emissions. 

The proposed changes are targeted to 

address issues identified during 

verification of reported data, where we 

have noticed that the activities 

conducted at certain facilities do not 

comport with some of the underlying 

assumptions of the steam generation 

model. The proposed changes will 

modify the current equation to more 

accurately estimate emissions and to be 

more universally applicable to these 

facilities. 

Additional details of these types of 

proposed changes are discussed in 

section III of this preamble. 

3. Revisions To Address Potential Gaps 

in Reporting of Emissions Data for 

Specific Sectors 

We are proposing several 

amendments to include reporting of 

additional emissions or emissions 

sources for specific sectors to address 

potential gaps in reporting. We are also 

proposing to improve the existing rule 

requirements by proposing new or 

revised calculation, monitoring, or 

reporting requirements that would help 

us to better understand and track 

emissions in specific sectors; establish 

requirements for a new source category 

for quantifying geologic sequestration of 

CO2 in association with EOR operations; 

and identify end uses of GHGs that are 

not currently accounted for in existing 

reporting, for consideration in future 

policy development. Such data would 

continue to inform, and are relevant to, 

the EPA’s carrying out a wide variety of 

CAA provisions. For example, 

identifying new emissions or new 

emission sources from direct emitters 

could inform decisions about whether 

and how to use section 111 of the CAA 

to establish NSPS for various source 

categories emitting GHGs. The data may 

also inform the EPA’s implementation 

of section 103(g) of the CAA regarding 

improvements in nonregulatory 

strategies and technologies for 

preventing or reducing air pollutants. 

The data published under the GHGRP 

serves to enable the Agency and 

stakeholders to understand, track, and 

compare greenhouse gas emissions and 

identify emission reduction 

opportunities. Over the last 10 years, the 

collection of these data 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 amendments we are 

proposing are intended to address data 

gaps that have been identified in the 

implementation of the program or from 

review of improved scientific 

assessments and would allow the EPA 

to better characterize U.S. GHG 

emissions. The improved data would 

subsequently better inform other agency 

policies and programs under the CAA. 

For example, we are proposing several 

revisions to subparts DD (Electrical 

Transmission and Distribution 

Equipment Use) and SS (Electrical 

Equipment Manufacture or 

Refurbishment) to improve the quality 

of the data collected from these 

industrial sectors. Currently, these 

subparts include ‘‘all electric 

transmission and distribution 

equipment and servicing inventory’’ 

used within an electric power system, 

and related manufacturing and 

refurbishing processes, that use or 

include sulfur hexafluoride (SF6) and 

perfluorocarbons (PFCs). When the final 

rule establishing subpart DD was 

published in 2010 (75 FR 74774, 

December 1, 2010, hereinafter referred 

to as the 2010 Final Rule for Additional 

Sources of Fluorinated GHGs), SF6 was 

the most commonly used insulating gas 

in the electrical power industry, and 

PFCs were occasionally used as 

dielectrics and heat transfer fluids in 

power transformers. During the 

implementation of the reporting 

program, electrical power systems 

equipment manufacturers and 

fluorinated greenhouse gas suppliers 


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3The terms ‘‘geologic sequestration’’ and 

‘‘geologic storage’’ are used synonymously for 

purposes of this subpart. 

have introduced alternative 

technologies and replacements for SF6

with lower GWPs, including fluorinated 

gas mixtures. We are proposing to revise 

the existing calculation, monitoring, and 

reporting requirements of these subparts 

to require reporting of additional F– 

GHGs, in order to better track emissions 

from equipment using alternative gases 

that are not currently accounted for. 

Additionally, we have become aware 

of potentially significant sources of 

emissions in specific industry sectors 

for which there are no current emission 

estimation methods within part 98. For 

example, under subpart I, we are 

proposing a calculation methodology to 

estimate emissions of perfluoromethane 

(CF4) from hydrocarbon-based emissions 

control systems. The proposed changes 

reflect recent studies that have shown 

that direct reaction between molecular 

fluorine (F2) and hydrocarbons to form 

CF4 can occur in hydrocarbon-fueled 

combustion emissions control systems, 

and we are proposing to incorporate 

calculations from the 2019 Refinement 

to account for the formation and 

emission of CF4 from this potentially 

significant emissions source. 

For subpart W, we are proposing to 

add calculation methodologies and 

requirements to report GHG emissions 

for several additional sources. We are 

proposing to add a new emissions 

source, referred to as ‘‘other large 

release events,’’ to capture abnormal 

emission events that are not accurately 

accounted for using existing methods in 

subpart W. This additional source 

would cover events such as storage 

wellhead leaks, well blowouts, and 

other large, atypical release events and 

would apply to all types of facilities 

subject to subpart W. Reporters would 

calculate GHG emissions using 

measurement data or engineering 

estimates of the amount of gas released 

and measurement data, if available, or 

process knowledge (best available data) 

to estimate the composition of the 

released gas. We are also proposing to 

require reporting of existing emission 

sources by additional industry 

segments. For example, we are 

proposing to require liquified natural 

gas (LNG) import/export facilities to 

begin calculating and reporting 

emissions from acid gas removal vents. 

In other cases, we are proposing 

changes to improve our understanding 

of end-uses of GHGs and to better 

understand GHG supply. For subpart 

OO (Suppliers of Industrial Greenhouse 

Gases), we are proposing to require 

suppliers of nitrous oxide (N2O), 

saturated PFCs, and SF6 to identify the 

end uses for which the N2O, SF6, or PFC 

is used, and the quantities of N2O, SF6, 

or each PFC transferred to each end use, 

if known. This requirement would help 

to inform the development of GHG 

policies and programs by providing 

information on N2O, SF6, and PFC uses 

and their relative importance, where the 

GWP-weighted quantities of these 

compounds that are supplied annually 

to the U.S. economy are relatively large, 

and where the identities and 

magnitudes of the uses of these 

compounds are less well understood. 

The EPA is also proposing revisions 

to incorporate a new source category to 

add calculation and reporting 

requirements for quantifying geologic 

sequestration of CO2 in association with 

EOR operations. The proposed 

requirements would be included under 

a new subpart VV and would apply to 

reporters that choose to use the 

International Standards Organization 

(ISO) standard designated as CSA Group 

(CSA)/American National Standards 

Institute (ANSI) ISO 27916:2019, 

Carbon Dioxide Capture, Transportation 

and Geological Storage—Carbon 

Dioxide Storage 3 Using Enhanced Oil 

Recovery (CO2-EOR) (hereafter referred 

to as ‘‘CSA/ANSI ISO 27916:2019’’) as a 

means of quantifying geologic 

sequestration. Under existing GHGRP 

requirements, facilities that sequester 

CO2 through EOR operations may opt 

into subpart RR. Proposed new subpart 

VV provides an alternative method of 

reporting geologic sequestration in 

association with CO2-EOR presenting 

another option for reporters who are 

sequestering CO2 through their EOR 

operations but do not choose to report 

under subpart RR. We are proposing to 

add this new source category because 

collecting additional information from 

these sources would improve our 

knowledge on the amounts of CO2 that 

are geologically sequestered in 

association with EOR operations and 

allow the Agency to more 

comprehensively track and document 

the flow of CO2 through the economy to 

better inform EPA policy and programs 

under the CAA related to the use of CO2

capture and geologic sequestration. 

Thus, the rationale for proposing 

subpart VV is analogous to the rationale 

for originally proposing and finalizing 

subpart RR, that is to enable the EPA to 

monitor the growth and efficacy of 

geologic sequestration as a greenhouse 

gas mitigation technology over time, to 

evaluate relevant policy options, and to 

reconcile information obtained with 

data obtained from 40 CFR part 98, 

subpart PP on CO2 supplied to the 

economy. The proposed requirements 

are discussed in section III.W of this 

preamble. 

The proposed changes would improve 

the overall quality and completeness of 

the data collected by the GHGRP, and 

would be useful for informing future 

policy decisions, such as opportunities 

to reduce emissions. The EPA is also 

soliciting additional comment on 

potential collection of data under other 

new source categories, as discussed in 

section IV of this preamble. 

4. Revisions to Reporting Requirements 

To Improve Verification and the 

Accuracy of the Data Collected 

The EPA is proposing several 

revisions to existing reporting 

requirements to improve the quality of 

the data that are currently reported, or 

to collect more useful data that would 

improve verification of reported data. 

Such revisions would better 

characterize U.S. GHG emissions and 

trends and would better enable the EPA 

to obtain data that is of sufficient quality 

that it can be used to support a range of 

future climate change policies and 

regulations, including but not limited to 

information relevant to carrying out 

provisions involving research, 

evaluating and setting standards, 

endangerment determinations, or 

informing EPA non-regulatory 

programs. 

For example, we are proposing 

revisions to the reporting of unit level 

information under subpart C. Currently, 

individual unit information (i.e., the 

unit type and the maximum rated heat 

input capacity) is only required to be 

reported for specific individual unit 

reporting configurations. The individual 

unit information allows the EPA to 

aggregate emissions according to unit 

type and size and provides a better 

understanding of the emissions from 

specific unit types. To improve 

verification and analysis of reported 

data, the EPA is proposing to require 

reporting of certain unit level 

information for each unit in an 

aggregation of units or common pipe 

configuration, excluding units less than 

10 million British thermal units per 

hour (mmBtu/hr). 

Under subpart H (Cement Production) 

and subpart S, we are proposing to 

collect additional data elements where 

the EPA has little data on which to 

build verification checks. For these 

subparts, we are proposing to collect 

annual averages of chemical 

composition input data on a facilitybasis. The proposed data elements 

would assist the EPA in verification of 

continuous emission monitoring 

systems (CEMS) facility emissions. 


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Because CEMS facilities typically 

include combustion and process 

emissions that are vented through the 

same stack, process and combustion 

emissions are usually mixed and 

indifferentiable. By collecting average 

chemical composition data, the EPA 

would be able to compare and 

differentiate process emissions from 

CEMS facilities. Such additions to 

reporting would improve the accuracy 

of the emissions data and render such 

information more valuable and useful. 

For subpart W, we are proposing to 

add or revise reporting requirements to 

better understand and characterize the 

emissions for several emission sources. 

For example, we are proposing to collect 

additional information from facilities 

with liquids unloadings to differentiate 

between manual and automated 

unloadings. 

Additionally, under subpart GG (Zinc 

Production), the EPA is proposing that 

facilities report the total amount of 

electric arc furnace (EAF) dust annually 

consumed by all Waelz kilns at the 

facility. In this case, because the amount 

of EAF dust consumed in Waelz kilns is 

strongly correlated with CO2 emissions, 

the proposed data element would serve 

as a useful data validation point and 

could potentially be used for the future 

development of an emission factor. 

The proposed revisions to add new 

reporting requirements would also 

extend the usefulness of GHGRP data to 

improve the EPA’s ability to carry out 

other CAA programs. For example, we 

are proposing under subpart HH to 

require MSW landfills to report data on 

the landfill CH4 emissions that are 

destroyed versus sent to landfill gas 

energy projects. This information would 

additionally help inform the 

development of GHG policies and 

programs by providing information on 

the amount of recovered CH4 that is 

beneficially used in energy recovery 

projects and would inform the EPA, as 

well as state and local government 

officials, on progress towards renewable 

energy targets, and would also be useful 

to other stakeholders. As discussed in 

prior amendments, the GHGRP is also 

intended to supplement and 

complement the U.S. GHG Inventory 

and other EPA programs by advancing 

the understanding of emission processes 

and monitoring methodologies for 

particular source categories or sectors. 

The GHGRP also provides data from 

individual facilities and suppliers above 

certain thresholds, which can 

additionally be used to improve the 

assumptions and emissions values used 

in the U.S. GHG Inventory (see 81 FR 

2546, January 15, 2016). The facility, 

unit, and process level GHG emissions 

data for industrial sources collected 

under the GHGRP does not replace the 

system in place to produce the topdown U.S. GHG Inventory, but can be 

additionally used to improve the 

accuracy of the U.S. GHG Inventory by 

confirming the national statistics and 

emission estimation methodologies. 

Therefore, the EPA periodically reviews 

the data from the GHGRP to consider 

whether there are data that are useful to 

the GHGRP and that would also 

improve the accuracy of the data 

included in the U.S. GHG Inventory or 

improve our ability to inform the 

development of GHG policies and 

programs. We are proposing several 

amendments that would improve the 

data collected by the GHGRP, and 

subsequently, would provide data that 

would benefit and support the U.S. GHG 

Inventory. For example, we are 

proposing to revise the current 

requirements for subpart N (Glass 

Production) facilities to require 

reporting the annual quantities of glass 

produced by glass type. In general, the 

emissions profile of a specific glass type 

is relatively consistent with the 

composition of the glass, based on the 

major raw materials (limestone, 

dolomite, and soda ash). Collecting data 

on annual production by glass type 

would improve verification for the 

GHGRP by allowing the EPA to compare 

emissions by glass types produced and 

would also provide useful information 

to improve analysis of this sector in the 

U.S. GHG Inventory. 

5. Technical Amendments, 

Clarifications, and Corrections 

We are proposing other technical 

amendments, corrections, and 

clarifications that would improve 

understanding of the rule. These 

revisions primarily include revisions of 

requirements to better reflect the EPA’s 

intent or editorial changes. Some of 

these proposed changes result from 

consideration of questions raised by 

reporters through the GHGRP Help Desk 

or electronic Greenhouse Gas Reporting 

Tool (e-GGRT) and are intended to 

resolve uncertainties in the regulatory 

text. For example, we are proposing 

amendments in several subparts that 

would clarify requirements that have 

led to reporter uncertainty, such as 

reported data elements that may be 

unclear and misread by reporters. In 

several cases, these provisions may have 

introduced uncertainty into the rule and 

resulted in reporting that is inconsistent 

with the rule requirements. The 

proposed clarifications would reduce 

the uncertainty associated with certain 

reported data elements and increase the 

likelihood that reporters will submit 

accurate reports the first time. For 

example, we are proposing a revision to 

subpart Y to resolve the potential 

discrepancy between the flare emission 

calculations at 40 CFR 98.253(b), which 

requires that all gas discharged through 

the flare stack must be included in the 

calculations except for pilot gas, and the 

requirements at 40 CFR 98.253(b)(1)(iii), 

which excludes startup, shutdown, and 

malfunction (SSM) events less than 

500,000 standard cubic feet per day (scf/ 

day) from equation Y–3. As another 

example, under subpart W, the EPA is 

proposing to clarify the calculation of 

emissions from open thief hatches on 

atmospheric storage tanks that use vapor 

recovery systems and flares, by revising 

40 CFR 98.233(j)(4) and (5) to specify 

how to account for those emissions. The 

EPA’s intent is that reporters should be 

including emissions from open thief 

hatches, but the current rule does not 

provide explicit provisions for them. We 

are also proposing to revise 40 CFR 

98.236(j)(1) to clarify reporting of 

emissions from atmospheric storage 

tanks with vapor recovery systems and 

flares. These proposed clarifications and 

corrections would also reduce the 

burden associated with reporting, data 

verification, and EPA review. 

Additional details of these types of 

proposed changes are discussed in 

section III of this preamble. 

Other minor changes being proposed 

include correction edits to fix typos, 

minor clarifications such as adding a 

missing word, harmonizing changes to 

match other proposed revisions, 

reordering of paragraphs so that a larger 

number of paragraphs need not be 

renumbered, and others as reflected in 

the draft proposed redline regulatory 

text in the docket for this rulemaking 

(Docket Id. No. EPA–HQ–OAR–2019– 

0424). 

B. Revisions To Streamline and Improve 

Implementation of 40 CFR Part 98 

Since 2010, the EPA has collected 

data through the GHGRP to assess 

industry emissions, and has, through 

review of annually submitted data, 

gained substantial knowledge of the 

types, quantities, and distribution of 

emissions across industry sectors. 

Through this process, the EPA has 

engaged in stakeholder outreach, 

solicited feedback, responded to 

questions from reporters, and identified 

site specific scenarios or issues that 

could impact the quality of the data 

reported. In a recent review of the 

requirements of the program, we have 

identified several areas of part 98 that 

could be revised or simplified to reduce 

technical challenges associated with 

implementation or improve the 


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efficiency of the requirements, while 

maintaining the quality of the data 

collected. We are subsequently 

proposing several revisions that would 

streamline the calculation, monitoring, 

and reporting burden associated with 

the rule. These revisions would revise 

applicability estimation methodologies, 

provide flexibility for or simplifying 

calculation and monitoring 

methodologies, streamline 

recordkeeping and reporting, and other 

minor technical corrections or 

clarifications. 

The specific changes that we are 

proposing that are intended to 

streamline part 98, as described in this 

section, are described in detail for each 

subpart in sections III.A through III.W of 

this preamble. 

1. Revisions To Applicability for Certain 

Industry Sectors 

We are proposing to change the 

applicability criteria for three subparts 

to account for changes in usage of 

certain GHGs, or where the current 

applicability estimation methodology 

may overestimate emissions. The 

proposed changes would improve the 

estimation methodologies used to 

determine applicability for specific 

subparts and more accurately focus 

GHGRP and reporter resources on 

coverage of large industrial emitters 

within these sectors; such changes are 

in keeping with our goal to maximize 

coverage and collection of GHG 

emissions data from each sector while 

excluding small emitters. 

Currently, any facility that contains a 

source category listed in Table A–3 of 

subpart A of part 98 (General 

Provisions) is subject to reporting under 

part 98 (referred to as ‘‘all-in’’ source 

categories because reporting applies 

regardless of other source category or 

stationary fuel combustion emissions at 

the facility). Table A–3 defines a few of 

the ‘‘all-in’’ source categories using 

thresholds that use metrics other than 

mtCO2e of emissions. A facility that 

contains a source category listed in 

Table A–4 of subpart A of part 98 must 

report only if estimated annual 

emissions from all applicable source 

categories in Tables A–3 and Table A– 

4 of part 98 are 25,000 mtCO2e or more 

(referred to as ‘‘threshold’’ source 

categories). The EPA has used the 

‘‘threshold’’ approach where a source 

category contains emitters with a range 

in emissions quantity and the EPA 

wants to capture those facilities within 

the source category with larger total 

emissions from multiple process units 

or collocated source categories that emit 

significant levels of GHGs collectively, 

and not burden smaller emitters with a 

reporting obligation. The EPA has used 

the ‘‘all-in’’ approach for industries for 

which all facilities are emitters of a 

similar quantity or to gather data on 

certain industries to identify the 

parameters that influence GHG 

emissions from the source category. 

The EPA used alternative metrics for 

some subparts in Table A–3 for a variety 

of reasons. In some cases, the metric 

provides a more straightforward way for 

facilities within that source category to 

evaluate their applicability. For 

example, for subpart DD (Electrical 

Transmission and Distribution 

Equipment), the metric is based on the 

total nameplate capacity of SF6 and 

PFC-containing equipment and was 

approximated as equivalent to the 

25,000 metric tons of CO2 threshold. To 

ensure that the GHGRP data collected 

better reflects the current electrical 

power system industry, we are 

proposing to remove the existing 

nameplate capacity threshold, and 

instead provide a calculation method for 

facilities to estimate total annual GHG 

emissions for comparison to the 25,000 

metric tons of CO2 threshold. These 

changes align with proposed changes to 

redefine the source category to include 

equipment containing ‘‘fluorinated 

GHGs (F–GHGs), including but not 

limited to sulfur-hexafluoride (SF6) or 

and perfluorocarbons (PFCs)’’, and 

reflect that some facilities within the 

industry sector have begun to use lower 

GWP F–GHGs, which is not reflected 

when using only the nameplate capacity 

of the equipment to determine 

applicability. The proposed changes 

would establish an updated comparison 

to the threshold and would account for 

additional fluorinated gases (including 

F–GHG mixtures) used in industry. The 

proposed changes to the threshold 

would decrease the number of facilities 

with annual emissions less than 25,000 

metric tons CO2e that would be required 

to report. The proposed changes would 

require tracking of additional 

fluorinated gases and the equipment 

they are contained in; however, this 

additional burden is expected to be 

small as these gases are not yet widely 

used. 

Similarly, we are proposing to revise 

the threshold for subpart SS (Electrical 

Equipment Manufacture or 

Refurbishment), which is based on total 

annual purchases of SF6 and PFCs. As 

with subpart DD, we are proposing to 

revise the existing requirements of 

subpart SS to require reporting of 

additional F–GHGs beyond SF6 and 

PFCs, and we are proposing to revise the 

subpart SS threshold to align with these 

changes. The proposed changes would 

continue to be based on the total annual 

purchases of F–GHGs but would 

establish a calculation method for 

comparison to the 25,000 metric tons of 

CO2 threshold, and would better 

account for the additional fluorinated 

gases (including F–GHG mixtures) 

reported by industry. The proposed 

changes would require tracking of 

additional fluorinated gases and the 

equipment they are contained in; 

however, this additional burden is 

expected to be small as these gases are 

not yet widely used. 

We are also proposing revisions to 

provide a second option for an 

alternative calculation methodology, 

that is consumption-based, that 

reporters subject to subpart I 

(Electronics Manufacturing) could use 

to determine whether they meet the 

emissions threshold for reporting 

applicability. For subpart I (Electronics 

Manufacturing), the current provisions 

of 40 CFR 98.91 require facilities to 

estimate whether the 25,000 metric tons 

of CO2e threshold is met based on 

emissions estimates assuming the 

facility operates at its annual 

manufacturing capacity, which may 

result in significant over-estimation of 

emissions. The capacity-based 

methodology has required reporting by 

some electronics manufacturing 

facilities that use smaller amounts of F– 

GHGs. For subpart I, the method for 

determining the applicability was 

chosen to reduce the burden on lowemitting facilities by providing a 

simplified method to estimate emissions 

for the purpose of assessing 

applicability. However, for subpart I, the 

applicability threshold provisions may 

currently require certain lower-emitting 

facilities to report where the capacitybased estimation methodology 

overestimates emissions. We are 

proposing to revise the applicability 

estimation methodology in subpart I to 

provide a second option for an 

alternative calculation method using a 

gas-consumption basis, and to use 

updated emission factors, so that 

facilities may choose instead to use a 

separate method that more accurately 

calculates potential facility emissions. 

This may result in fewer facilities 

reporting under subpart I, but these 

facilities are expected to have annual 

emissions that are lower than 25,000 

metric tons of CO2e. The gas 

consumption-based approach to 

determining applicability would require 

tracking gas consumption, which is not 

required by the production capacitybased threshold when determining 

applicability; however, this option to 

determine applicability is less 

burdensome than reporting to subpart I, 


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which a facility would be required to do 

under the current rule if their capacity 

were above the capacity-based 

threshold. Under the current rule, 

facilities reporting under subpart I must 

collect gas consumption data to 

complete their subpart I report. Thus, 

overall, the burden for potential new 

entrants to the program would decrease. 

We are proposing to revise the 

applicability of these subparts to more 

accurately estimate facility emissions 

and to more accurately focus GHGRP 

and reporter resources on the collection 

of data for the larger industrial emitters 

within these sectors. These changes 

would continue to maximize coverage of 

GHG emissions data from the sector 

while excluding small emitters. The 

proposed revisions would also adjust 

the applicability provisions for each of 

these subparts for consistency across 

part 98. The proposed changes to 

subparts I, DD, and SS are described in 

sections III.E, III.N, and III.U of this 

preamble. 

2. Revisions To Streamline Monitoring 

and Calculation Methodologies 

We are proposing revisions to provide 

flexibility for or simplify some 

calculation methods or monitoring 

requirements. We are proposing options 

to revise monitoring requirements in 

instances where we currently allow a 

less burdensome methodology for 

similar emissions sources; or where 

continuing to collect the data on the 

same frequency would be unlikely to 

provide significantly different values. 

In some cases, we are proposing 

amendments that would add flexibility 

to the calculation methods to add less 

burdensome options that would 

correspond with a decrease in actual 

data collection. These types of proposed 

changes would simplify monitoring for 

reporters without impacting the quality 

of the data reported. For example, for 

subpart Y (Petroleum Refineries), we are 

proposing to allow the use of mass 

spectrometer analyzers to determine gas 

composition and molecular weight 

without the use of a gas chromatograph. 

The proposed revisions would allow 

reporters to use the same analyzers used 

for process control or for compliance 

with continuous sampling required 

under the National Emissions Standards 

for Hazardous Air Pollutants from 

Petroleum Refineries (40 CFR part 63, 

subpart CC) to comply with the GHGRP 

requirements in subpart Y. Currently, 

these reporters must conduct separate 

periodic sampling of these gas streams 

for analysis using gas chromatography 

to comply with GHGRP requirements in 

subpart Y, and the proposed revisions 

would provide flexibility for and reduce 

burden for these reporters. 

We are also proposing to clarify 

applicability provisions to reduce 

uncertainty regarding which calculation 

method should be used. For example, 

for subpart W (Petroleum and Natural 

Gas Systems), we are proposing to revise 

the definition of the Onshore Natural 

Gas Processing industry segment so that 

reporters have more certainty regarding 

the industry segment and calculation 

methods that are applicable from the 

beginning of the year. The current 

definition of the Onshore Natural Gas 

Processing industry segment includes 

processing plants that fractionate gas 

liquids and processing plants that do 

not fractionate gas liquids but have an 

annual average throughput of 25 million 

standard cubic feet (MMscf) per day or 

greater. Processing plants that do not 

fractionate gas liquids and have an 

annual average throughput of less than 

25 MMscf per day may be part of a 

facility in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segment. Processing plants that 

do not fractionate gas liquids and 

generally operate close to the 25 MMscf 

per day threshold do not know until the 

end of the year whether they will be 

above or below the threshold, so they 

must be prepared to report under 

whichever industry segment is 

ultimately applicable. The two 

potentially applicable segments report 

emissions from different sources and 

with different calculation methods. For 

example, facilities in the Onshore 

Natural Gas Processing industry 

segment are not required to report 

emissions from atmospheric storage 

tanks and are required to measure leaks 

from individual compressors, while 

facilities in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segment are required to report 

emissions from atmospheric storage 

tanks but may use emission factors to 

calculate emissions from compressors 

rather than conducting measurements. 

Therefore, we are proposing to revise 

the Onshore Natural Gas Processing 

industry segment definition in 40 CFR 

98.230(a)(3) to remove the 25 MMscf per 

day threshold and more closely align 

subpart W with the definitions of 

natural gas processing in other rules 

(e.g., 40 CFR part 60, subpart OOOOa). 

This proposed revision to the Onshore 

Natural Gas Processing industry 

segment definition would make it clear 

to reporters whether a processing plant 

would be classified as an Onshore 

Natural Gas Processing facility or as part 

of an Onshore Petroleum and Natural 

Gas Gathering and Boosting facility, and 

the applicable segment would not have 

the potential to change from one year to 

the next simply based on the facility 

throughput. As discussed in greater 

detail in section III.J.2.h of this 

preamble, we are also proposing several 

other changes to the Onshore Natural 

Gas Processing industry segment 

definition. Collectively, these proposed 

amendments are not expected to 

significantly affect the overall coverage 

of the GHGRP for the petroleum and 

natural gas systems industry, although 

we anticipate that some facilities would 

report under a different industry 

segment going forward. 

Additional details of these types of 

proposed changes may be found in 

section III of this preamble. 

3. Revisions To Streamline or Revise 

Recordkeeping and Reporting 

Requirements 

Other proposed revisions to the rule 

include changes that would streamline 

the rule, such as revising certain 

reporting and recordkeeping 

requirements that are redundant or no 

longer being used, or that would remove 

duplicative reporting across EPA 

programs. For example, for subpart C 

(General Stationary Fuel Combustion 

Sources), we are proposing to amend 

certain provisions in 40 CFR 98.36 that 

require facilities with the aggregation of 

units or common pipe configuration 

types to report the total annual CO2

mass emissions from the combustion of 

all fossil fuels combined. In this case, 

the reported configuration-level annual 

CO2 emissions from all fossil fuels does 

not factor into any subpart- or facilitylevel total CO2 emission calculations 

and is not integrated into e-GGRT’s 

programmed ‘‘roll up’’ of emissions. 

Because we can adequately verify 

reports and interpret and analyze the 

reported data without these data 

elements, they are currently redundant 

and would not likely provide new 

insights or knowledge of the industry 

sector, emissions, or trends at this time. 

In some cases, we are proposing to 

correct inconsistencies in the current 

rule. Under subpart Y, we are proposing 

a change to correct an inconsistency 

introduced by the amendments to the 

DCU calculations published on 

December 9, 2016 (81 FR 89188). 

Although the prior amendments 

removed the option to calculate CH4

emissions from DCUs using the process 

vent method, the associated 

recordkeeping requirements for the 

process vent method were inadvertently 

not removed from the rule. Therefore, 

we are therefore proposing to remove 

the associated recordkeeping 

requirements. 


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For subpart W, we are proposing to 

revise reporting requirements related to 

atmospheric pressure fixed roof storage 

tanks receiving hydrocarbon liquids that 

follow the methodology specified in 40 

CFR 98.233(j)(3) and equation W–15. 

The calculation methodology uses 

population emission factors and the 

count of applicable separators, wells, or 

non-separator equipment to determine 

the annual total volumetric GHG 

emissions at standard conditions. The 

associated reporting requirements in 40 

CFR 98.236(j)(2)(i)(E) through (F) 

require reporters to delineate the counts 

used in equation W–15. Based on 

feedback from reporters, the EPA has 

determined that the reporting 

requirements are inconsistent with the 

language used in the calculation 

methodology and are not inclusive of all 

equipment to be included. Therefore, 

we are proposing to revise the reporting 

requirements to better align the 

requirement with the calculation 

methodology and streamline the 

requirements for all facilities reporting 

atmospheric storage tanks emissions 

using the methodology in 40 CFR 

98.233(j)(3). 

In some cases, we are streamlining 

reporting by removing duplicative 

reporting elements within or across 

GHGRP subparts. For example, we are 

proposing to eliminate duplicative 

reporting between subpart NN 

(Suppliers of Natural Gas and Natural 

Gas Liquids) and subpart W where both 

subparts require similar data elements 

to be reported to e-GGRT. For instance, 

for fractionators of natural gas liquids 

(NGLs), both subpart W (under the 

Onshore Natural Gas Processing 

segment) and subpart NN require 

reporting of the volume of natural gas 

received and the volume of NGLs 

received. The proposed amendments 

would limit the reporting of these data 

elements to facilities that do not report 

under subpart NN, thus removing the 

duplicative requirements from subpart 

W for facilities that report to both 

subparts. This will streamline reporting 

and reduce the burden on reporters. 

We are also proposing to reduce the 

frequency of reporting information that 

we anticipate will not change on a 

frequent basis, such as the data 

collected for technology assessment 

reports under subpart I (Electronics 

Manufacturing). Based on the data 

collected in the initial technology 

assessment reports (currently required 

by 40 CFR 98.96(y)), we do not 

anticipate significant variations in these 

data elements within a three-year period 

going forward, as discussed in section 

III.E.2 of this preamble. Further, we are 

proposing several significant 

improvements to the technology 

assessment reports that will improve the 

usefulness and quality of the data 

provided in the reports. The proposed 

improvements would allow the EPA to 

collect these data less frequently while 

continuing to provide the EPA with 

updates to the gases and technologies 

used in semiconductor manufacturing. 

Additional details of these types of 

proposed changes may be found in 

section III of this preamble. 

C. Revisions to 40 CFR Part 9 

The EPA is proposing a related 

change to update 40 CFR part 9 to 

include the OMB control number issued 

under the PRA for the ICR for the 

GHGRP. The OMB control numbers for 

EPA regulations in Title 40 of the CFR 

(after appearing in the Federal Register) 

are listed in 40 CFR part 9 and are 

included on the related collection 

instrument or form, if applicable. The 

EPA is proposing to amend the table in 

40 CFR part 9 to list the OMB approval 

number under which the ICR for 

activities in the existing part 98 

regulations that were previously 

approved by OMB have been 

consolidated. The prior approvals are 

included in OMB No. 2060–0629; OMB 

No. 2060–0629 has not previously been 

added to 40 CFR part 9 due to an 

oversight. This listing of the OMB 

control number and the subsequent 

codification in the CFR would correct 

this oversight and satisfy the display 

requirements of the PRA and OMB’s 

implementing regulations at 5 CFR part 

1320. 

III. Proposed Amendments to 40 CFR 

Part 98 

This section summarizes the specific 

substantive amendments proposed for 

each subpart, as generally described in 

section II of this preamble. The impacts 

of the proposed revisions are 

summarized in section VII of this 

preamble. A full discussion of the cost 

impacts for the proposed revisions may 

be found in the memorandum, 

Assessment of Burden Impacts for 

Proposed Revisions for the Greenhouse 

Gas Reporting Rule available in the 

docket for this rulemaking, Docket Id. 

No. EPA–HQ–OAR–2019–0424. 

A. Subpart A—General Provisions 

1. Proposed Revisions To Improve the 

Quality of Data Collected for Subpart A 

In this action, we are proposing 

several clarifying revisions to subpart A 

of part 98 (General Provisions). For the 

reasons described in section II.A.5 of 

this preamble, we are proposing to 

clarify in 40 CFR 98.2(i)(1) and (2) 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 proposed changes 

clarify that reporters must rely on the 

emissions estimation methodologies 

used to report emissions and their 

annual emissions report totals to 

determine their ability to off-ramp. We 

are also proposing to clarify the offramp provisions at 40 CFR 98.2(i)(1) and 

(2) to specify that after an owner or 

operator off-ramps, the owner or 

operator must use equation A–1 and 

follow the requirements of 40 CFR 

98.2(b)(4) in subsequent years to 

determine if emissions exceed the 

25,000 mtCO2e applicability threshold 

and whether the facility or supplier 

must resume reporting. The 

requirements of 40 CFR 98.2(b) are 

different from the requirements of 40 

CFR 98.3(c) in that the applicability 

determination requires more flexible 

calculation methods (e.g., facilities may 

use any subpart C tier to estimate 

combustion emissions on 40 CFR 

98.2(b), whereas they must follow the 

applicable subpart C tier to calculate 

combustion emissions under 40 CFR 

98.3(c)). The proposed revisions make 

clear that reporters who have previously 

off-ramped would continue to follow 

the emission estimation methods used 

for determination of applicability to 

determine if they must resume 

reporting. 

We are also proposing to revise 40 

CFR 98.2(f)(1) to clarify how to calculate 

GHG quantities for comparison to the 

25,000 mtCO2e threshold for importers 

and exporters of industrial greenhouse 

gases; the proposed changes specify that 

the calculation must include the 

fluorinated heat transfer fluids (F–HTFs) 

that are imported or exported during the 

year. In the December 9, 2016 final rule, 

2015 Revisions and Confidentiality 

Determinations for Data Elements 

Under the Greenhouse Gas Reporting 

Rule (81 FR 89234), the EPA expanded 

the definition of the source category for 

importers and exporters of industrial 

greenhouse gases to include facilities 

that destroy 25,000 mtCO2e or more of 

industrial F–GHGs or F–HTFs annually, 

and entities that produce, import, or 

export F–HTFs that are not also F– 

GHGs. It was our intent that suppliers 

of F–HTFs be subject to the same 


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4 In the 2016 proposed rule, we specified 

‘‘Suppliers of fluorinated HTFs would be subject to 

the same thresholds as suppliers of fluorinated 

GHGs. That is, there would be no threshold for 

producers of fluorinated HTFs, but the threshold for 

importers, exporters, and destroyers of fluorinated 

HTFs would be 25,000 mtCO2e of fluorinated HTFs 

or GHGs.’’ (81 FR 2572, January 15, 2016). 

5U.S. EPA. Q749: ‘‘What are the notification 

requirements when an Onshore Petroleum and 

Natural Gas Production facility, reporting under 

subpart W, sells wells and associated equipment in 

a basin?’’ September 26, 2019. https://

ccdsupport.com/confluence/pages/ 

viewpage.action?pageId=198705183. Note that 

although FAQ Q749 specifically describes facilities 

in the Onshore Petroleum and Natural Gas 

Production segment, the EPA does consider the 

scenarios described to be relevant to the Onshore 

Petroleum and Natural Gas Gathering and Boosting 

industry segment as well, because facilities in both 

segments are defined at the basin level rather than 

at the level of the subpart A definition of facility. 

thresholds.4 However, we inadvertently 

neglected to update 40 CFR 98.2(f) to 

include F–HTFs in the calculation 

requirements. Similarly, we are 

proposing to add a new paragraph (k) to 

40 CFR 98.2, specifying 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. This paragraph 

was inadvertently omitted when the 

rule was revised to cover stand-alone 

destruction facilities in 2016. The 

proposed changes would clarify that 

imported, exported, and destroyed F– 

HTFs and F–GHGs must be calculated 

and included when determining 

applicability. 

We are also proposing new paragraph 

40 CFR 98.4(n) that would apply in lieu 

of 40 CFR 98.4(h) for changes in the 

owner or operator of a facility in the 

four industry segments in subpart W 

(Petroleum and Natural Gas Systems) 

that have unique definitions of facility: 

Onshore Petroleum and Natural Gas 

Production; Onshore Petroleum and 

Natural Gas Gathering and Boosting; 

Natural Gas Distribution; and Onshore 

Natural Gas Transmission Pipeline. For 

these industry segments, particularly 

Onshore Petroleum and Natural Gas 

Production and Onshore Petroleum and 

Natural Gas Gathering and Boosting, 

asset transactions between owners and 

operators can involve only some 

emission sources at the facility rather 

than the entire facility. In those cases, 

reporters have submitted numerous 

questions to the e-GGRT Help Desk 

requesting guidance regarding which 

owner or operator should report for the 

year in which the transaction occurred 

as well as which owner or operator is 

responsible for submitting revisions and 

responding to questions from the EPA 

regarding previous annual GHG reports. 

To address some of these questions, the 

EPA previously developed Frequently 

Asked Questions (FAQ) Q749.5

However, neither the FAQ nor the 

existing requirements in subpart A 

explicitly explain the responsibilities 

for the situations for which reporters 

have requested guidance. 

Therefore, the EPA is proposing to 

add specific provisions to subpart A that 

would define which owner or operator 

is responsible for current and future 

reporting years’ reports and clarify how 

to determine responsibility for revisions 

to annual reports for reporting years 

prior to owner or operator changes for 

specific industry segments in subpart 

W, beginning with RY2023 reports. The 

provisions would also specify when an 

owner or operator should submit an 

annual report using an e-GGRT 

identifier assigned to an existing facility 

and when an owner or operator should 

register a new facility in e-GGRT. As 

described in more detail in this section, 

the provisions would vary based upon 

whether the selling owner or operator 

will retain any emission sources, the 

number of purchasing owners or 

operators, and whether the purchasing 

owners or operators already report to 

the GHGRP in the same industry 

segment and basin or state (as 

applicable). The proposed provisions 

would apply in lieu of 40 CFR 98.4(h) 

for these industry segments. These 

proposed revisions are expected to 

improve data quality as described in 

section II.A.4 of this preamble by 

ensuring that the EPA receives a more 

complete data set, and they are also 

expected to improve understanding of 

the rule, as described in section II.A.5 

of this preamble. 

We expect all the transactions will fall 

into one of four general categories, and 

we are proposing provisions that would 

define the responsibilities for reporting 

for each of those general categories. 

First, if the entire facility is sold to a 

single purchaser and the purchasing 

owner or operator does not already 

report to the GHGRP in that industry 

segment (and basin or state, as 

applicable), then we are proposing that 

the facility’s certificate of representation 

must be updated within 90 days of the 

transaction to reflect the new owner or 

operator. In other words, the e-GGRT 

identifier and associated facility within 

e-GGRT would be transferred from the 

seller to the purchaser. The purchasing 

owner or operator would be responsible 

for submitting the facility’s annual 

report for the entire reporting year in 

which the acquisition occurred (i.e., the 

owner or operator as of December 31 

would be responsible for the report for 

that entire reporting year) and each 

reporting year thereafter. In addition, 

because the definitions of facility for 

each of these segments encompass all of 

the emission sources in a particular 

geographic area (i.e., basin, state, or 

nation), the purchasing owner or 

operator would include any previously 

owned applicable emission sources in 

the same geographic area as part of the 

purchased facility beginning with the 

reporting year in which the acquisition 

occurred. 

Second, if the entire facility is sold to 

a single purchaser and the purchasing 

owner or operator already reports to the 

GHGRP in that industry segment (and 

basin or state, as applicable), then we 

are proposing that the purchasing owner 

or operator would merge the acquired 

facility with their existing facility for 

purposes of reporting under the GHGRP. 

In other words, the acquired facility 

would become part of the purchaser’s 

existing facility under the GHGRP and 

emissions for the combined facility 

would be reported under the e-GGRT 

identifier for the purchaser’s existing 

facility. The purchaser would update 

the acquired facility’s certificate of 

representation within 90 days of the 

transaction to reflect the new owner or 

operator. The purchaser would then 

follow the provisions of 40 CFR 

98.2(i)(6) to notify the EPA that the 

purchased facility has merged with their 

existing facility and would provide the 

e-GGRT identifier for the merged, or 

reconstituted, facility. Finally, the 

purchaser would be responsible for 

submitting the merged facility’s annual 

report for the entire reporting year in 

which the acquisition occurred (i.e., the 

owner or operator as of December 31 

would be responsible for the report for 

that entire reporting year) and each 

reporting year thereafter. 

Third, if the selling owner or operator 

retains some of the emission sources 

and sells the other emission sources of 

the seller’s facility to one or more 

purchasing owners or operators, we are 

proposing that the selling owner or 

operator would continue to report under 

subpart W for the retained emission 

sources unless and until that facility 

meets one of the criteria in 40 CFR 

98.2(i) and complies with those 

provisions. Each purchasing owner or 

operator that does not already report to 

the GHGRP in that industry segment 

(and basin or state, as applicable) would 

begin reporting as a new facility for the 

entire reporting year beginning with the 

reporting year in which the acquisition 

occurred. The new facility would 

include the acquired applicable 

emission sources as well as any 

previously owned applicable emission 


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36934 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

sources. Each purchasing owner or 

operator that already reports to the 

GHGRP in that industry segment (and 

basin or state, as applicable) would add 

the acquired applicable emission 

sources to their existing facility for 

purposes of reporting under subpart W 

and would be responsible for submitting 

the annual report for their entire facility, 

including the acquired emission 

sources, for the entire reporting year 

beginning with the reporting year in 

which the acquisition occurred. 

Fourth, if the selling owner or 

operator does not retain any of the 

emission sources and sells all of the 

facility’s emission sources to more than 

one purchasing owner or operator, we 

are proposing that the selling owner or 

operator for the existing facility would 

notify the EPA within 90 days of the 

transaction that all of the facility’s 

emission sources were acquired by 

multiple purchasers. The purchasing 

owners or operators would begin 

submitting annual reports for the 

acquired emission sources for the 

reporting year in which the acquisition 

occurred following the same provisions 

as in the third scenario. In other words, 

each owner or operator would either 

begin reporting their acquired 

applicable emission sources as a new 

facility or add the acquired applicable 

emission sources to their existing 

facility. 

Finally, for all of these types of 

transactions, we are proposing one set of 

provisions to clarify responsibility for 

annual GHG reports for reporting years 

prior to the reporting year in which the 

acquisition occurred. This set of 

proposed provisions would apply to 

annual GHG reports for facilities where 

these types of transactions occur after 

the effective date of the final 

amendments, if adopted. In other words, 

if the effective date of the final 

amendments is January 1, 2023, as 

described in section V of this preamble, 

then for ownership transactions that 

occur on or after January 1, 2023, we are 

proposing that the proposed 

requirements for the current and future 

reporting years described in the 

previous paragraphs would apply. In 

addition, the proposed provisions for 

annual GHG reports for reporting years 

prior to the transaction would also 

apply. For example, if an ownership 

transaction occurs on June 30, 2025, 

then the selling owner or operator and 

purchasing owner or operator would 

follow the applicable provisions 

previously described in this section for 

the RY2025 report and for future 

reporting years. We are also proposing 

that the provisions described in the next 

paragraph would apply for RY2024 and 

prior years’ reports. 

Specifically, we are proposing that as 

part of each ownership transaction 

described previously in this section, the 

selling owner or operator and 

purchasing owner or operator would 

agree upon the entity that would be 

responsible for revisions to annual GHG 

reports for previous reporting years. 

That entity would then select a 

representative for each facility that 

would respond to any EPA questions 

regarding GHG reports for previous 

reporting years and would submit 

corrected versions of GHG reports for 

previous reporting years as needed. If 

that individual is not the designated 

representative for the facility, the 

individual would need to be appointed 

as the alternate designated 

representative or an agent for the 

facility. In many situations, particularly 

for the first two categories of 

transactions described in this section, 

the EPA expects that the purchaser 

would agree to select a representative to 

address revisions to previous years’ 

annual GHG reports. In addition, there 

may be cases in which the selling owner 

or operator’s company will no longer be 

operating after the transaction, so it may 

be appropriate for one of the purchasing 

owners or operators to select that 

representative. In other situations, the 

parties may determine that it is 

appropriate for the seller to select the 

representative to address revisions to 

annual GHG reports for reporting years 

prior to the reporting year in which the 

acquisition occurred. Alternatively, 

parties to the transaction may agree on 

another independent party that would 

act as the representative regarding 

annual GHG reports for previous 

reporting years, such as a consultant. 

The EPA expects that the decision 

regarding the responsible entity would 

be made as part of the acquisition 

agreement or ownership transfer 

contract between the selling owner or 

operator and purchasing owner or 

operator and that if the entity 

responsible for revisions to annual GHG 

reports is not the selling owner or 

operator, copies of the records required 

to be retained per 40 CFR 98.3(g) and (h) 

would be transferred to the responsible 

entity at that time. 

We are also proposing to amend 40 

CFR 98.1(c) to clarify that the terms 

‘‘owner’’ and ‘‘operator’’ used in subpart 

A have the same meaning as the terms 

‘‘gathering and boosting system owner 

or operator’’ and ‘‘onshore natural gas 

transmission pipeline owner or 

operator’’ for the Onshore Petroleum 

and Natural Gas Gathering and Boosting 

and Onshore Natural Gas Transmission 

Pipeline industry segments of subpart 

W, respectively. This paragraph was 

inadvertently not amended when those 

two industry segments and the industry 

segment-specific definitions of owner or 

operator were added to subpart W (80 

FR 64275, October 22, 2015), and this 

proposed amendment would correct 

that oversight. 

In addition, we are proposing to 

revise 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. According 

to 40 CFR 98.3(h) a substantive error 

may either be identified by the EPA or 

discovered by the facility itself. If 

discovered by the facility, a revised 

report correcting the error must be 

submitted within 45 days. If identified 

by the EPA, once the facility is notified 

of the error, the facility must either 

resubmit the corrected report or provide 

information demonstrating that the 

previously submitted report does not 

contain the identified substantive error 

within 45 days. The rule also states that 

if requested in either case, the EPA may 

provide reasonable extensions to the 45- 

day period, including an automatically 

granted extension of 30 days. Additional 

extensions may be granted if the facility 

submits a request that is received prior 

to the expiration of the automatic 30- 

day extension. The current rule states 

that the Administrator will approve the 

additional extension request if the 

request demonstrates that it is not 

practicable to collect and process the 

data needed to resolve potential 

reporting errors within 75 days. 

However, since the GHGRP was 

implemented, we have encountered 

instances where a facility has repeatedly 

requested an extension of the time 

period by which they must either 

submit a revised report or provide 

information that the previously 

submitted report does not contain a 

substantive error. As such, the EPA 

cannot verify the facility’s report in a 

timely manner. To avoid such instances 

in the future, we are proposing to add 

to 40 CFR 98.3(h)(4) that the 

Administrator will only approve 

extension requests for a total of 180 days 

from the initial notification of a 

substantive error. We expect 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. 


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6WMO. Scientific Assessment of Ozone 

Depletion: 2018, Global Ozone Research and 

Monitoring Project–Report No. 58, 588 pp., Geneva, 

Switzerland, 2018. https://www.esrl.noaa.gov/csd/ 

assessments/ozone/2018/downloads/ 

2018OzoneAssessment.pdf. Retrieved July 29, 2019. 

Available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

The EPA is also proposing revisions 

to two terms consistent with the 

proposed amendments for reporting for 

glycol dehydrators with an annual 

average daily natural gas throughput 

greater than or equal to 0.4 MMscf per 

day described in section III.J of this 

preamble. The EPA is proposing to 

amend the definition of ‘‘dehydrator 

vent emissions’’ in 40 CFR 98.6 to 

confirm that dehydrator emissions 

reporting should include emissions 

from both the dehydrator still vent, and 

if applicable, the dehydrator flash vent. 

Additionally, the EPA is proposing to 

amend the definition of ‘‘vapor recovery 

system’’ in 40 CFR 98.6 to clarify that 

routing emissions from a dehydrator 

vent to the regenerator firebox/fire tubes 

does not qualify as vapor recovery. The 

EPA has noted significant variability in 

the dehydrator emissions values 

reported over the past several years, 

with values ranging from extremely high 

to almost negligible emissions, which 

indicates that there are likely 

inconsistencies in how these terms are 

being interpreted among subpart W 

reporters. In making these clarifying 

edits, the EPA expects to improve the 

quality of the emissions data reported 

and alleviate any confusion surrounding 

the applicability of these terms. 

As a corollary to proposed 

amendments to subpart W to remove 

desiccant dehydrators as an emissions 

source, we are proposing to remove the 

definition of ‘‘desiccant’’ and to revise 

the definition of ‘‘dehydrator’’ in 40 

CFR 98.6. The definition of ‘‘desiccant’’ 

would no longer be needed if the 

emission calculation and reporting 

requirements for desiccant dehydrators 

are removed from subpart W, as 

discussed in section III.J of this 

preamble. Similarly, the definition of 

‘‘dehydrator’’ would no longer need to 

include a reference to desiccant. Thus, 

we are proposing to revise the definition 

of ‘‘dehydrator’’ to indicate that a 

dehydrator is ‘‘a device in which a 

liquid absorbent (e.g., ethylene glycol, 

diethylene glycol, or triethylene glycol) 

directly contacts a natural gas stream to 

absorb water vapor.’’ 

We are proposing revisions to 40 CFR 

98.6 to add a definition for ‘‘Direct air 

capture’’ and amend the definition of 

‘‘Carbon dioxide stream’’. These 

proposed changes are being made in 

conjunction with other proposed 

revisions to subpart PP of part 98 

(Suppliers of Carbon Dioxide) and are 

discussed in section III.T of this 

preamble. 

In addition, we are proposing two 

harmonizing changes to 40 CFR 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) 

for subpart Q (Iron and Steel 

Production) and CSA/ANSI ISO 

27916:2019, Carbon Dioxide Capture, 

Transportation and Geological 

Storage—Carbon Dioxide Storage Using 

Enhanced Oil Recovery (CO2-EOR) for 

proposed subpart VV (Geologic 

Sequestration of Carbon Dioxide with 

Enhanced Oil Recovery Using ISO 

27916). These proposed changes are 

further described in sections III.H and 

III.W of this preamble. 

Lastly, we are proposing two updates 

to Table A–1, the list of GWPs used in 

the GHGRP, to revise GWPs that, based 

on recent information, overestimate the 

atmospheric impacts of certain 

compounds by a large margin (i.e., by 

factor of 2,000). We are not proposing 

any other updates to the Table A–1 

GWPs. First, we are proposing to adopt 

a chemical-specific GWP for carbonic 

difluoride (COF2). Emissions of COF2 of 

1–2 metric tons per year have been 

reported under the GHGRP from 

fluorinated gas production. (Carbonic 

difluoride is also used in the electronics 

industry as an etching agent and surface 

treatment, although emissions of COF2

from electronics manufacturing have not 

been reported under the GHGRP). No 

peer-reviewed, chemical-specific GWP 

was available for COF2 in 2014, when 

we last updated the set of GWPs in 

Table A–1 (79 FR 73750, December 11, 

2014). It is therefore currently classified 

as an ‘‘Other fluorinated GHG’’ and is 

assigned a default GWP of 2,000 under 

the GHGRP. However, the World 

Meteorological Organization (WMO) 

recently published an atmospheric 

lifetime, radiative efficiency, and GWP 

for COF2 in its Scientific Assessment of 

Ozone Depletion 6 (2018). Like the IPCC 

Assessment Reports upon which the 

GWPs in Table A–1 are based, the WMO 

Scientific Assessments include regularly 

updated international reviews of the 

scientific findings on the impacts of 

trace gases in the atmosphere, including 

their atmospheric lifetimes and 

radiative efficiencies. According to the 

2018 WMO Scientific Assessment, COF2

has a lifetime of approximately seven 

days, and 20-year and 100-year GWPs of 

less than one. The 2018 WMO Scientific 

Assessment listed the 100-year GWP of 

COF2 as ‘‘<1,’’ so we calculated and are 

proposing a precise GWP for COF2 of 

0.14 using the atmospheric lifetime and 

radiative efficiency provided in the 

2018 WMO Scientific Assessment. (The 

method we used to calculate the GWP 

of COF2 was the method we used to 

calculate precise GWPs for low-GWP 

compounds in the most recent update to 

GHGRP GWPs (79 FR 73750, December 

11, 2014)). This recent information 

supports that including a chemicalspecific GWP for COF2 of 0.14 would 

reflect its atmospheric impacts far more 

accurately than the currently applied 

GHGRP default GWP of 2,000. 

Second, we are proposing to expand 

one of the F–GHG groups to which a 

default GWP of 1 is applied to include 

additional unsaturated fluorocarbons. 

The ninth F–GHG group in Table A–1 

to subpart A currently includes 

unsaturated PFCs, unsaturated HFCs, 

unsaturated hydrochlorofluorocarbons 

(HCFCs), unsaturated halogenated 

ethers, unsaturated halogenated esters, 

fluorinated aldehydes, and fluorinated 

ketones. We are proposing to add 

unsaturated bromofluorocarbons, 

unsaturated chlorofluorocarbons, 

unsaturated bromochlorofluorocarbons, 

unsaturated hydrobromofluorocarbons, 

and unsaturated 

hydrobromochlorofluorocarbons to this 

set. These F–GHGs do not have 

chemical-specific GWPs in Table A–1, 

and facilities and suppliers that 

currently report these F–GHGs generally 

classify them as ‘‘Other fluorinated 

GHGs,’’ which are assigned a default 

GWP of 2,000. However, two lines of 

evidence indicate that unsaturated 

bromofluorocarbons, unsaturated 

chlorofluorocarbons, unsaturated 

bromochlorofluorocarbons, unsaturated 

hydrobromofluorocarbons, and 

unsaturated 

hydrobromochlorofluorocarbons are 

likely to have GWPs near 1. First, like 

many of the types of compounds 

currently included in the ninth F–GHG 

group, they are unsaturated (i.e., they 

include double and triple bonds 

between carbon atoms), and unsaturated 

GHGs in general tend to have very short 

atmospheric lifetimes and GWPs near or 

below 1. Second, evaluations of 

individual unsaturated 

chlorofluorocarbons and unsaturated 

bromofluorocarbons have all found very 

short atmospheric lifetimes and (where 

assessed) low GWPs for these 

compounds. The 2018 WMO Scientific 

Assessment provides atmospheric 

lifetimes for three unsaturated 

chlorofluorocarbons and four 

unsaturated bromofluorocarbons, and it 

provides an atmospheric lifetime and a 

100-year GWP for one unsaturated 


jspears on DSK121TN23PROD with PROPOSALS2
36936 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

7The IPCC Fifth Assessment Report lists 100-year 

GWPs of less than one for all the compounds for 

which the report lists an atmospheric lifetime of 

less than 8 days. The IPCC Fifth Assessment Report 

is the source of the chemical-specific GWPs for the 

compounds in the ninth F–GHG group in Table A– 

1. See 2013: Anthropogenic and Natural Radiative 

Forcing. In: Climate Change 2013: The Physical 

Science Basis. Contribution of Working Group I to 

the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change. 

https://www.ipcc.ch/site/assets/uploads/2018/02/ 

WG1AR5_Chapter08_FINAL.pdf. 

bromochlorofluorocarbon (4-bromo-3- 

chloro-3,4,4-trifluoro-1-butene). All of 

the atmospheric lifetimes are under 8 

days,7 and the 100-year GWP is listed as 

‘‘<1.’’ Therefore, the EPA’s assessment 

is that, due to their short atmospheric 

lifetimes, unsaturated 

bromofluorocarbons, unsaturated 

chlorofluorocarbons, unsaturated 

bromochlorofluorocarbons, unsaturated 

hydrobromofluorocarbons, and 

unsaturated 

hydrobromochlorofluorocarbons are 

likely to have a GWP near 1 (the default 

GWP for the ninth F–GHG group) rather 

than 2,000 (the default GWP for ‘‘Other 

Fluorinated GHGs’’). The EPA is 

proposing to add these additional 

unsaturated fluorocarbons to the ninth 

F–GHG group to result in more accurate 

estimation of the reported mtCO2e. 

We are proposing to incorporate a 

harmonizing change based on the 

addition of a new source category for 

quantifying geologic sequestration in 

association with EOR operations. 

Specifically, we are proposing to add 

the new subpart, subpart VV (Geologic 

Sequestration of Carbon Dioxide with 

Enhanced Oil Recovery Using ISO 

27916), in Table A–3 to subpart A. 

As discussed in section III.W of this 

preamble, facilities that conduct EOR 

currently have the option to either 

report basic information on CO2

received under subpart UU (Injection of 

Carbon Dioxide), or report CO2

sequestered under subpart RR (Geologic 

Sequestration of Carbon Dioxide). 

Facilities that conduct EOR are not 

required to report under subpart RR 

unless the owner or operator chooses to 

opt-in to subpart RR, or the well is 

permitted as an Underground Injection 

Control (UIC) Class VI well. We are 

proposing that facilities that use the 

standard Carbon Dioxide Capture, 

Transportation and Geological 

Storage—Carbon Dioxide Storage Using 

Enhanced Oil Recovery (CO2-EOR) 

(CSA/ANSI ISO 27916:2019) for 

quantifying geologic sequestration of 

CO2 in association with EOR operations 

would similarly have the option to 

report under the proposed subpart VV 

instead of subpart UU. Facilities that 

conduct EOR would therefore have two 

options to report amounts of CO2 that 

are geologically sequestered: subpart RR 

or subpart VV. 

We are proposing to include the new 

subpart VV in Table A–3 to subpart A. 

In addition, we are proposing that this 

new subpart would not include a 

reporting threshold for applicability. 

The EPA previously promulgated 

subparts RR and UU with no threshold 

(i.e., as ‘‘all-in’’ source categories in 

Table A–3 to subpart A) due to 

variability in CO2 injection amounts 

from year to year and based on limited 

knowledge of which EOR reporters that 

are not required to report under subpart 

RR would choose to report geologic 

sequestration (see 75 FR 18454, April 

10, 2010 and 75 FR 75070, December 1, 

2010). The facilities affected by the 

proposed subpart include facilities that 

are currently reporting under subpart 

UU and that do not currently report 

amounts of CO2 sequestered. The EPA is 

proposing no threshold for the proposed 

subpart VV so that all EOR facilities that 

quantify CO2 sequestration using the 

CSA/ANSI ISO 27916:2019 standard 

and that do not report under subpart RR 

would have the option to either report 

under the proposed subpart VV, or 

would otherwise continue to report 

under subpart UU. For these reasons, we 

do not anticipate that the new subpart 

would increase the number of facilities 

subject to the GHGRP. Further, it is 

difficult to predict how many injection 

facilities would choose to report using 

the ISO standard in lieu of continuing 

to report under subpart UU. Therefore, 

we are proposing that subpart VV would 

be an ‘‘all-in’’ reporting subpart in order 

to allow the Agency to continue to 

comprehensively track all CO2 that is 

injected underground, and to remain 

consistent with the ‘‘all-in’’ 

requirements for EOR or injection 

facilities that currently report under 

subparts RR or UU. Reporters who 

choose to report under this subpart 

would be required to meet the 

requirements of 40 CFR 98.2(a)(1). 

However, as proposed in new 40 CFR 

98.480(c), facilities subject only to new 

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 the existing facilities under subpart 

UU. 

Additionally, we are proposing that 

facilities subject to proposed subpart VV 

would not be required to meet the offramp requirements of 40 CFR 98.2(i). 

Instead, once a facility opts-in to 

proposed 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 27916:2019. The EPA is 

proposing that the operator 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 

27916:2019. See section III.W of this 

preamble for additional details on the 

proposed revisions. 

2. Proposed Amendments To Streamline 

and Improve Implementation for 

Subpart A 

For the reasons described in sections 

II.B.1, III.N, and III.U of this preamble, 

we are proposing harmonizing edits in 

subpart A of part 98 to revise the rule 

applicability for subparts DD (Electrical 

Transmission and Distribution 

Equipment Use) and subpart SS 

(Electrical Equipment Manufacture or 

Refurbishment). The proposed 

applicability threshold for subparts DD 

and SS would be based on total 

emissions equivalent to the 25,000 

mtCO2e or more per year, rather than 

the current threshold levels that are 

based on the total nameplate capacity of 

the equipment or the annual 

consumption, respectively. For subpart 

DD, we are proposing to revise Table A– 

3 such that the threshold is based on 

total estimated emissions from F–GHGs, 

as determined under 40 CFR 98.301 

(subpart DD), that are equivalent to 

25,000 mtCO2e or more per year. For 

subpart SS, we are proposing to revise 

Tables A–3 and Tables A–4 such that: 

(1) subpart SS would be removed from 

Table A–3; and (2) Table A–4 would be 

revised to specify that subpart SS 

facilities would be included in 40 CFR 

98.2(a)(2) and Table A–4, as determined 

under the requirements of 40 CFR 

98.451 (subpart SS), which provide 

estimation methods for total estimated 

emissions from F–GHGs for comparison 

to a threshold equivalent to 25,000 

mtCO2e or more per year. Refer to 

sections III.N and III.U of this preamble 

for a detailed discussion of these 

proposed changes and how the 

proposed new thresholds would be 

implemented. The proposed revisions 

are intended to harmonize Tables A–3 

and A–4 with the proposed changes 

described in sections II.B.1, III.N, and 

III.U of this preamble, which would 

update the threshold to be consistent 

with the threshold set for the majority 

of subparts and would account for 

additional fluorinated gases (including 

F–GHG mixtures) reported by industry, 

and for subpart DD, would also 

streamline the reporting requirements to 


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Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 36937 

8ASTM D7459–08 was approved for use in the 

October 30, 2009 final rule (74 FR 56291), see 

Docket Id. No. EPA–HQ–OAR–2008–0508. ASTM 

D6866–16 was approved for use in the December 9, 

2016 final rule (81 FR 89196), see Docket Id. No. 

EPA–HQ–OAR–2015–0526. 

focus Agency resources on the 

substantial emission sources within the 

sector by excluding facilities or 

operations that may report emissions 

that are consistently and substantially 

below 25,000 mtCO2e per year (see 

section IV.C (‘‘Rationale for Selection of 

Thresholds’’) of the preamble to the 

2009 Proposed Rule (74 FR 16467, April 

10, 2009)). 

B. Subpart C—General Stationary Fuel 

Combustion Sources 

1. Proposed Revisions To Improve the 

Quality of Data Collected for Subpart C 

We are proposing several 

amendments to improve the quality of 

the data collected under subpart C of 

part 98 (General Stationary Fuel 

Combustion Sources). This section 

describes the specific changes proposed. 

First, for the reasons provided in 

section II.A.2 of this preamble, we are 

proposing to modify the Tier 3 

calculation methodology in subpart C. 

Reporters to subpart C may use the Tier 

3 methodology provided in 40 CFR 

98.33(a)(3) for determining annual CO2

emissions from combustion units. The 

Tier 3 methodology requires a 

calculation based on annual fuel use, 

measured carbon content, and for 

gaseous fuels, measured molecular 

weight. For gaseous fuels, equation C– 

5 at 40 CFR 98.33(a)(3)(iii) requires that 

the carbon content and molecular 

weight be in units of kilogram (kg) C/kg 

fuel and kg/kg-mole, respectively, and 

be determined using the same 

procedures as specified for high heating 

value (HHV) at 40 CFR 98.33(a)(2)(ii). 

However, when using equation C–2b at 

40 CFR 98.33(a)(2)(ii)(A) in this manner, 

the fuel carbon content is on a mass 

basis (i.e., kg C/kg fuel) while the fuel 

flow is on a volumetric basis (i.e., scf), 

resulting in a weighting factor that is 

potentially problematic because the 

units of measure are not in equivalent 

terms, i.e., the average annual carbon 

content should be in mass terms (i.e., kg 

C/kg fuel). When using equation C–2b 

for calculating an annual flow-weighted 

molecular weight, a similar situation 

occurs. This has been the case since the 

2009 Final Rule (74 FR 56397). 

To address this matter, the EPA is 

proposing to modify the Tier 3 

calculation methodology in 40 CFR 

98.33(a)(3)(iii) to provide new equations 

C–5a and C–5b for calculating a 

weighted annual average carbon content 

and a weighted annual average 

molecular weight. respectively. These 

new proposed equations incorporate the 

molar volume conversion factor at 

standard conditions (as defined at 40 

CFR 98.6) and for annual average carbon 

content, the measured molecular weight 

of the fuel, in order to convert the fuel 

flow to the appropriate units of 

measure. This proposed change will 

correct the calculation method for Tier 

3 gaseous fuels. The EPA does not 

expect a significant change in reported 

emissions because the change to the 

values for carbon content and molecular 

weight is expected to be minimal under 

the proposed calculation methods. 

Additionally, some reporters have 

previously exercised the option to 

manually override the calculated 

emission values with their own 

calculated values to address this issue 

when it has been identified. 

We are also proposing several 

revisions to rule provisions pertaining 

to the calculation of biogenic emissions 

from tire combustion to improve the 

existing calculation methodology. First, 

for the reasons described in section 

II.A.2 of this preamble, the EPA is 

proposing to revise the calculation 

methods that must be used to determine 

the total annual CO2 emissions under 40 

CFR 98.33(e)(3)(iv)(A) when 

determining the biogenic CO2 emissions 

of MSW or tires under 40 CFR 

98.33(e)(3)(iv). Currently, 40 CFR 

98.33(e)(3)(iv) provides procedures in 

certain circumstances to estimate the 

annual biogenic CO2 emissions in the 

combustion of MSW or tires, which start 

with requiring that the Tier 1 

calculation method be used to 

determine the total annual CO2

emissions from MSW or tires under 40 

CFR 98.33(e)(3)(iv)(A). The value 

determined under 40 CFR 

98.33(e)(3)(iv)(A) is then multiplied by 

the applicable default biogenic fraction 

specified at 40 CFR 98.33(e)(3)(iv)(B) to 

determine the total biogenic CO2

emissions. At the same time, 40 CFR 

98.33(a) provides four calculation 

methodologies, Tier 1 through 4, and an 

alternative methodology for certain 

units subject to 40 CFR part 75, for 

calculating CO2 emission for fuel 

combustion. In certain circumstances, a 

reporter may be required under 40 CFR 

98.33(a) to calculate CO2 emissions from 

combustion of MSW or tires using Tiers 

2 or 3 for the purposes of annual 

reporting, but then must also calculate 

the total CO2 emissions using Tier 1 

under 40 CFR 98.33(e)(3)(iv)(A) for the 

purpose of determining and reporting 

the biogenic CO2 emissions from 

combustion of MSW or tires under 40 

CFR 98.33(e)(3)(iv). This has previously 

resulted in some confusion for reporters 

where total CO2 emissions are 

calculated twice using different tiers, 

one tier for one aspect of annual 

reporting and another tier for biogenic 

calculation and reporting, and a 

redundancy in calculation of total CO2

emissions by reporters. This has also 

resulted in some confusion when 

comparing the calculated total CO2

emissions under 40 CFR 98.33(a) to the 

estimated total biogenic CO2 emissions 

under 40 CFR 98.33(e)(3)(iv), since they 

are based on different calculation 

methodologies. The EPA is proposing to 

revise 40 CFR 98.33(e)(3)(iv)(A) so that 

total annual CO2 emissions will be 

calculated using the applicable 

methodology in paragraphs 40 CFR 

98.33(a)(1) through (3) for units using 

Tier 1 through 3 for purposes of 40 CFR 

98.33(a), and using the Tier 1 

calculation methodology in paragraph 

40 CFR 98.33(a)(1) for units using the 

Tier 4 or part 75 for purposes of 40 CFR 

98.33(a), when determining the biogenic 

component of MSW or tires under 40 

CFR 98.33(e)(3)(iv). 

The EPA is proposing two additional 

substantive revisions to the procedures 

for calculating and reporting emissions 

of biogenic CO2 from the combustion of 

tires. First, for the reasons discussed in 

section II.A.1 of this preamble, we are 

proposing to update a default factor that 

is used to determine biogenic CO2

emissions from the combustion of tires. 

Separately reporting the biogenic CO2

emissions (i.e., specifying which 

emissions are biogenic) from the 

combustion of tires is currently 

optional, but if a reporter elects to do so, 

then 40 CFR 98.33(e)(3) specifies the 

calculation procedure. Under 40 CFR 

98.33(e)(3), if tires provide more than 10 

percent of the annual heat input to a 

unit and the owner or operator elects to 

separately report the biogenic CO2

emissions from the combustion of tires, 

then the owner or operator must 

conduct testing using ASTM method 

D6866–16, Standard Test Methods for 

Determining the Biobased Content of 

Solid, Liquid, and Gaseous Samples 

Using Radiocarbon Analysis (2016) and 

ASTM method D7459–08, Standard 

Practice for Collection of Integrated 

Samples for the Speciation of Biomass 

(Biogenic) and Fossil-Derived Carbon 

Dioxide Emitted from Stationary 

Emissions Sources (2016) to determine 

the biogenic fraction of CO2.8 But if tires 

provide 10 percent or less of the annual 

heat input, then reporters have the 

option to separately report the biogenic 

CO2 emissions by multiplying the total 

CO2 emissions by a default factor of 

0.20. The 0.20 factor is based on 


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9Please refer to the memorandum, Natural 

Rubber Fraction in Tire Derived Fuel by Matt Hakos 

and Cassy Becker, RTI International to Michael 

Hannan, EPA (August 2021), available in the docket 

for this rulemaking, Docket Id. No EPA–HQ–OAR– 

2019–0424, for more detail. 

10See the memorandum, Methodology for 

Determining the Natural Rubber Fraction in Tire 

Derived Fuel, by Sarah Amick and Jesse Levine, 

USTMA to U.S. EPA (April 11, 2019), available in 

Docket Id. EPA–HQ–OAR–2019–0424. 

11Supra note 9. 

12See ‘‘Tire Biogenic Content Data Provided by 

the Portland Cement Association’’ (August 2021), 

available in Docket Id. EPA–HQ–OAR–2019–0434. 

13Supra note 9. 

14Supra note 9. 

information from the Rubber 

Manufacturers Association (RMA) that 

was based on most current data 

available at the time of the publication 

of the GHG Reporting Rule revisions in 

the Federal Register on December 17, 

2010 (75 FR 79092) (hereafter referred to 

as the 2010 Final Revisions Rule) and 

represented an arithmetic average of the 

natural rubber content (i.e., 

composition) of passenger and 

commercial tires sold and thus available 

for combustion.9 Since publication of 

the 2010 Final Revisions Rule, we have 

received a memorandum from the U.S. 

Tire Manufacturers Association 

(USTMA, formerly RMA) that based on 

updated data, the weighted average 

composition of natural rubber in tires is 

now 24 percent.10 11 The proposed 

default value was calculated by 

weighting the average rubber content, 

average weight, and shipment 

percentage of both light duty vehicle 

and commercial vehicle scrap tires, 

which is more accurate than would 

result from using the arithmetic average. 

In addition to the comments and 

information provided by the USTMA, 

the Portland Cement Association (PCA) 

provided supporting information from 

one of its member companies, 

Mitsubishi Cement. Operational data 

(total count and weight of tires 

combusted) and analytical data (percent 

of biogenic carbon based on ASTM 

D6866–20) from 2020 was provided.12

The EPA reviewed these data and 

determined that they support the 

USTMA’s recommended 0.24 default 

biogenic fraction for tires.13 We are 

therefore proposing to revise 40 CFR 

98.33(e)(3)(iv)(B) to update the default 

biogenic fraction to 0.24.14

Second, for the reasons described in 

section II.A.3 of this preamble, we are 

proposing that all units that combust 

tires must separately report biogenic 

CO2 emissions. The separate reporting 

of biogenic CO2 from tires was made 

optional in a 2010 final rule (75 FR 

79100, December 17, 2010). For that 

rulemaking, we received no public 

comments on the proposal to make 

separate biogenic CO2 emissions 

reporting optional for the combustion of 

tires, and the proposal was finalized 

without modification. In the final rule 

preamble, however, we stated: ‘‘No 

comments were received on the 

proposal to make biogenic CO2

emissions reporting optional for the 

combustion of tires, and the proposal 

has been finalized without modification. 

However, tire-derived fuel has a 

biomass component, and perhaps it 

should be treated in the same manner as 

MSW, which is also partly biogenic. A 

number of units that are subject to part 

98 combust tires as the primary fuel or 

as a secondary fuel. Therefore, we are 

considering whether these units should 

be required to separately account for 

their biogenic CO2 emissions. However, 

before making this mandatory we intend 

to open it to notice and comment in a 

future rulemaking’’ (75 FR 79109). In 

conjunction with this change, we are 

proposing to remove the restriction in 

40 CFR 98.33(e)(3)(iv) that the default 

factor may only be used to estimate the 

annual biogenic CO2 emissions from the 

combustion of tires if the combustion of 

tires represents ‘‘no more than 10 

percent annual heat input to a unit.’’ 

Following the 2010 Final Revisions 

Rule, reporters that chose to optionally 

report biogenic CO2 emissions from tire 

combustion were required to use 

quarterly flue-gas testing using ASTM 

methods, except that small units (i.e., 

units in which tires provide no more 

than 10 percent of the annual heat input 

to a unit) could alternatively use the 

default factor. The proposal to remove 

the current restriction allowing only 

small units to use the default factor (i.e., 

allowing the use of the default factor for 

all units that combust tires), when 

combined with the proposed 

requirement to report biogenic CO2

emissions from tire combustion, would 

result in a more accurate 

characterization of emissions from 

larger units since no units that combust 

tires alone or in conjunction with fossil 

fuels have reported, for RY2015 through 

RY2018, biogenic CO2 emissions that 

were calculated using the quarterly fluegas testing results. Therefore, the 

proposed addition of reporting of 

biogenic CO2 emissions for tire 

combustion should require no 

additional monitoring or data collection 

and could be reported with minimal 

additional reporting burden. The EPA is 

proposing that this change would only 

be finalized if the proposed requirement 

to report biogenic CO2 emissions from 

tire combustion is also finalized. 

Additionally, we are proposing another 

change that would only be finalized if 

the proposed requirement to report 

biogenic CO2 emissions from tire 

combustion is also finalized. 

Specifically, 40 CFR 98.33(b)(1)(vii) 

currently allows units that combust 

MSW and/or tires to use Tier 1 if the 

combined heat input from both fuels is 

not greater than 10 percent of the heat 

input to the unit but also provides that, 

if a reporter choose the option to not 

report biogenic CO2 from tire 

combustion, the 10 percent threshold 

applies only to the MSW fuel. If the 

proposed mandatory reporting of 

biogenic CO2 from tire combustion is 

finalized, we are proposing that the 

additional provision in 40 CFR 

98.33(b)(1)(vii) on how to apply the 

threshold to only MSW fuel would be 

deleted, since it would no longer be 

applicable. This may result in fewer 

facilities being able to use Tier 1 to 

calculate MSW and/or tire CO2

emissions since the tire heat input 

would now always be included in 

conjunction with the MSW heat input to 

compare to the 10 percent threshold. 

In conjunction with these proposed 

revisions, we are also proposing to 

remove the language in 40 CFR 98.33(e) 

and 40 CFR 98.36(e)(2)(xi) referring to 

optional biogenic CO2 emissions 

reporting from tire combustion, and to 

revise 40 CFR 98.34(d) to reference 40 

CFR 98.33(e)(3)(iv) instead of 40 CFR 

98.33(b)(1)(vi) and (vii). We are 

proposing the latter change because 40 

CFR 98.34(d) incorrectly references 40 

CFR 98.33(b)(1)(vi) and (vii), which 

specify certain provisions when Tier 1 

can be used, whereas 40 CFR 

98.33(e)(3)(iv) specifies when the 

default biogenic factor for MSW can be 

used (i.e., in cases where combustion of 

MSW provides no more than 10 percent 

of the annual heat input to the unit or 

if a small, batch incinerator combusts no 

more than 1,000 tons per year of MSW) 

and is the correct reference for 40 CFR 

98.34(d). This revision is being 

proposed to correct this reference in 

accordance with other proposed 

changes. Additionally, we are proposing 

a clarifying correction to 40 CFR 

98.33(e), Biogenic CO2 emissions from 

combustion of biomass with other fuels. 

Section 98.33(e)(1) specifies that 

equation C–1 of subpart C can be used 

to calculate the annual CO2 mass 

emissions from the combustion of the 

biomass fuels listed in Table C–1 of this 

subpart (except MSW and tires). We are 

proposing to delete the parenthetical 

clause ‘‘(except MSW and tires)’’ in 40 

CFR 98.33(e)(1) because, although MSW 

and tires are partially biogenic, they 

were never categorized as biomass fuels 


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in Table C–1 of subpart C and thus no 

aspect of Table C–1 was excepted by 

this parenthetical clause. This deletion 

would correct the drafting oversight and 

will not result in any change to the 

reporting requirements. 

Next, for the reasons discussed in 

section II.A.5 of this preamble, we are 

proposing to correct the equation C–11 

term definition for the variable ‘‘R’’. 

Equation C–11 is used to calculate the 

CO2 emissions from sorbent use when 

the chemical reaction between the acid 

gas and sorbent produces CO2 emissions 

and when these emissions are not 

monitored with a CEMS. The term ‘‘R’’ 

is currently defined as the number of 

moles of CO2 released upon capture of 

one mole of the acid gas species being 

removed (R = 1.00 when the sorbent is 

CaCO3 and the targeted acid gas species 

is SO2). However, the units of measure 

for the equation as presented do not 

currently result in metric tons CO2

emitted. We are proposing to revise the 

definition of the term ‘‘R’’ as ‘‘the 

number of moles of CO2 released per 

mole of sorbent used (R = 1.00 when the 

sorbent is CaCO3 and the targeted acid 

gas species is SO2)’’ so that the equation 

is dimensionally correct (i.e., results in 

metric tons CO2 emitted). 

We are also proposing to amend 40 

CFR 98.33(c)(6)(i), (ii), (ii)(A), and 

(iii)(C), and delete (ii)(B) to clarify the 

methods used to calculate CH4 and N2O 

emissions for blended fuels when heat 

input is determined after the fuels are 

mixed and combusted. There would be 

no new reporting requirements because 

of this proposed clarification. 

For the reasons described in section 

II.A.4 of this preamble, we are 

proposing a substantive revision to rule 

provisions pertaining to the reporting of 

unit level information for the 

aggregation of units and common pipe 

configurations. Currently, subpart C 

allows facilities to report data using six 

different configurations. These 

configurations are: 

• Individual unit using Tiers 1, 2, or 

3 to calculate emissions. 

• Individual unit using Tier 4 to 

calculate emissions. 

• Group of units using the aggregation 

of units reporting alternative with Tiers 

1, 2 or 3. 

• Group of units using the common 

pipe configuration reporting alternative 

with Tiers 1, 2, or 3. 

• Group of units using Tier 4 to 

calculate emissions and reporting under 

the monitored common stack or duct 

configuration reporting alternative. 

• Part 75 units using the alternative 

CO2 mass emissions calculation 

methods. 

• For RY2019, the approximate use of 

reporting configurations and the percent 

of emissions for each is summarized: 

Configuration type 

Number of 

Subpart C 

configurations 

Percent 

of total 

Subpart C 

configurations 

Percent of 

total Subpart 

C CO2

emissions 

Individual Unit (Tiers 1–3) ........................................................................................................... 9,185 58 36 

Individual Unit (Tier 4) ................................................................................................................. 208 1 9 

Aggregation of Units (Tiers 1–3) ................................................................................................. 4,362 27 24 

Common Pipe (Tiers 1–3) ........................................................................................................... 1,905 12 26 

Common Stack (Tier 4) ............................................................................................................... 21 0.1 2 

Alternative Part 75 ....................................................................................................................... 192 1 2 

Individual unit information (i.e., the 

unit type and the maximum rated heat 

input capacity) is currently only 

required to be reported for the 

individual unit (Tiers 1–3 and Tier 4) 

reporting configurations. The individual 

unit information allows the EPA to 

aggregate emissions according to unit 

type and size and provides a better 

understanding of the emissions from 

specific unit types. 

Individual unit information is not 

reported for the aggregation of units, 

common pipe, common stack, or 

alternative part 75 reporting 

configurations. As such, the EPA is 

currently unable to aggregate emissions 

by unit type and size for these reporting 

configurations, which represent 40 

percent of the configurations used and 

54 percent of the emissions reported in 

subpart C. 

The aggregation of units and common 

pipe configurations are the second and 

third most used configurations and 

together, they represent approximately 

39 percent of the configurations and 50 

percent of the emissions reported to 

subpart C. Both of these reporting 

alternatives allow multiple units to be 

reported under one configuration group. 

Because the unit type and maximum 

rated heat input capacity are currently 

not reported for the individual units 

within these two configurations, there is 

a significant gap in the EPA’s ability to 

aggregate subpart C emissions data by 

unit type and size. 

To better analyze reported data by 

unit type and size, the EPA is proposing 

to revise 40 CFR 98.36(c)(1) and (3) (by 

adding 40 CFR 98.36(c)(1)(ii) and 

(c)(3)(xi)) to require reporting for each 

unit in either an aggregation of units or 

common pipe configuration, excluding 

units less than 10 mmBtu/hr from both, 

of the unit type, maximum rated heat 

input capacity, and an estimate of the 

fraction of the total annual heat input. 

Under the proposed amendments, unit 

level information would be reported for 

four of the six configuration types. This 

would allow the EPA to aggregate data 

according to unit type and size for 

approximately 98 percent of the 

configurations and 95 percent of the 

emissions in subpart C (the actual 

percent of emissions that could be 

aggregated by unit type would be 

somewhat lower than 95 percent 

because units less than 10 would be 

excluded from the additional reporting 

requirements) to provide unit level 

information for the aggregated unit and 

common pipe configurations. We expect 

the percent of emissions to be only 

somewhat lower than 95 percent 

because units less than 10 mmBtu/hr are 

estimated to have minor emissions 

contributions in aggregated unit and 

common pipe configurations, as 

previously described in the 2016 final 

rulemaking (81 FR 89203, December 9, 

2016). Given the relatively low 

emissions from the common stack (Tier 

4) and part 75 configurations, the EPA 

is not proposing to require reporting of 

individual unit information for these 

configurations at this time. The EPA 

seeks comment on whether to propose 

these requirements for the common 

stack (Tier 4) and part 75 configurations. 

The proposed reporting requirements 

are not expected to significantly 

increase burden for reporters. The 

requirement to report the cumulative 

maximum rated heat input capacity for 

the aggregation of units or common pipe 

configurations began with the 2017 

reporting year (81 FR 89188). 

Accordingly, facilities have been 

reporting cumulative maximum rated 

heat input capacity for four years. To 

determine this value, facilities must 

know the maximum rated heat input 

capacity of all units in each aggregation 


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of units or common pipe configuration 

(greater than or equal to 10 mmBtu/hr), 

because these values are summed to 

determine the cumulative value. The 

EPA expects that the other requirements 

(i.e., unit type and estimate of the 

fraction of annual heat input) can be 

determined from existing company 

records. The total fraction of annual 

heat input for each unit in the group 

will be determined by dividing the 

estimated actual heat input for that unit 

by the sum of the estimated actual heat 

input for all units in the group. 

Accordingly, any new burden incurred 

from this proposed requirement is 

expected to be minimal and associated 

with calculating the fraction of the total 

annual heat input and entering data into 

the e-GGRT software. To minimize the 

burden of reporting these data in eGGRT, the EPA intends to evaluate 

developing a bulk unit details reporting 

form similar to the existing bulk 

equation input reporting forms for Tiers 

2 and 3. 

For the reasons described, the EPA 

has proposed these new reporting 

requirements under 40 CFR 

98.36(c)(1)(ii) (aggregation of units) and 

40 CFR 98.36(c)(3)(xi) (common pipe). 

These proposed amendments will better 

inform future policy and programs by 

addressing a data gap in unit 

information that currently exists for 

these two reporting configurations. We 

are proposing related confidentiality 

determinations for the additional data 

elements, as discussed in section VI of 

this preamble. 

As a corollary to proposed 

amendments to subpart W (Petroleum 

and Natural Gas Systems) to address 

uncombusted methane emissions from 

compressor drivers (see section III.J.1.n 

of this preamble), we are proposing that 

natural gas-fired compressor drivers 

located at facilities that are subject to 

subpart W would be required to use the 

CH4 emission factors in Table W–9 to 

subpart W rather than the default CH4

emission factor for natural gas in Table 

C–2 to subpart C. Specifically, we are 

proposing to revise the ‘‘EF’’ term in 

each of the equations in 40 CFR 98.33(c) 

(i.e., equations C–8, C–8a, C–8b, C–9a, 

C–9b, and C–10) to reference the CH4

emission factors in Table W–9 to 

subpart W for natural gas compressor 

drivers. We are also proposing to add a 

footnote to Table C–2 that specifies that 

for reporters subject to subpart W, the 

default CH4 emission factor for natural 

gas may only be used for natural gasfired combustion units that are not 

compressor drivers. Finally, we are 

proposing to amend 40 CFR 98.36(c)(1) 

and (c)(3). Under the proposed 

amendments, reporters may not report a 

combination of one design class of 

compressor driver (using one Table W– 

9 CH4 emission factor) and other 

combustion units (e.g., using a Table C– 

2 CH4 emission factor or another Table 

W–9 CH4 emission factor) in the same 

aggregation of units or common pipe 

configuration. This change would 

ensure that all units in an aggregation of 

units or common pipe configuration are 

using the same CH4 emission factor for 

each fuel combusted in the unit. 

We are proposing two additional 

clarifications to existing reporting and 

record keeping requirements, for the 

reasons described in section II.A.5 of 

this preamble. First, we are proposing to 

revise the first sentence of 40 CFR 

98.36(e)(2)(ii)(C) to clarify that both the 

annual average, and, where applicable, 

monthly high heat values are required to 

be reported. The monthly HHV 

reporting requirement was always clear 

based on the language in this provision 

and the proposed clarification plainly 

states that the annual average high heat 

value is also a reporting requirement 

(for reporters who do not use the 

electronic inputs verification tool (IVT) 

within e-GGRT). There are no new 

reporting requirements because of this 

proposed clarification. 

Second, we are proposing to revise 40 

CFR 98.37(b)(9), (10), (11), (14), (18), 

(20), (22), and (23) to specify 

recordkeeping data that is currently 

contained in the file generated by the 

verification software that is already 

required to be retained by reporters 

under 40 CFR 98.37(b) but was 

inadvertently omitted from being 

specified in those subparagraphs. These 

proposed revisions correct omissions 

that currently exist in the verification 

software recordkeeping requirements 

specific to equations C–2a, C–2b, C–3, 

C–4, and C–5. They also align the 

verification software recordkeeping 

requirements with the proposed 

revisions to equation C–5 at 40 CFR 

98.33(a)(3)(iii), as noted above. These 

proposed revisions do not require any 

new action from affected reporters, as 

all new recordkeeping data proposed is 

already contained in the file generated 

by the verification software. 

2. Proposed Revisions To Streamline 

Implementation and Reduce Burden for 

Subpart C 

We are proposing several revisions to 

subpart C to streamline requirements 

and to adopt minor revisions to improve 

implementation of the rule. 

For the reasons described in section 

II.B.2 of this preamble, the EPA is 

proposing to amend 40 CFR 98.34(c)(6). 

In the 2010 Final Revisions Rule (75 FR 

79092), the EPA added 40 CFR 

98.34(c)(6), which allowed cylinder gas 

audits (CGAs) of the CO2 monitor to be 

performed using calibration gas 

concentrations of 40–60 percent and 80– 

100 percent of CO2 span, when the CO2

span value is set higher than 20 percent 

CO2. Under appendix F of 40 CFR part 

60, CGAs of the CO2 analyzer are 

required at two calibration gas 

concentrations (i.e., 5–8 percent and 10– 

14 percent CO2 by volume). These CO2

concentration levels are appropriate for 

certain stationary combustion 

applications (e.g., a typical span value 

for a CO2 monitor installed on a coalfired boiler is 20 percent CO2). These 

CGA concentrations represent 25–40 

percent and 50–70 percent of the CO2

span value, when the CO2 span is at 20 

percent CO2. When the CO2 span 

exceeds the typical span value of the 

fuel being evaluated (e.g., 20 percent 

CO2 on a coal-fired boiler), the CGA 

concentrations specified in part 60 are 

no longer representative, as they only 

evaluate the lower portion of the 

measurement scale. Since the EPA had 

information indicating that there were 

cases when the CO2 span was set greater 

than 20 percent CO2 (e.g., process and 

combustion emissions from cement 

manufacturing may require 30 percent 

CO2 span), 40 CFR 98.34(c)(6) was 

added so that CGAs could be conducted 

at two separate portions of the 

measurement scale, as opposed to just 

the lower portion (see 75 FR 79111, 

December 17, 2010). 

Since 2010, the EPA has received 

questions through GHGRP Help Desk 

indicating that industrial flue gases also 

occur where the measured CO2

concentration is very low (e.g., natural 

gas turbines typically have about 5 

percent CO2 in flue gas). In this case, the 

required calibration gas concentrations 

(i.e., 5–8 percent and 10–14 percent CO2

by volume) under appendix F of 40 CFR 

part 60 would not be appropriate 

because they may be above the CO2 span 

value and so would not provide 

information regarding accuracy of the 

monitor at actual representative stack 

gas concentrations. Accordingly, the 

EPA is proposing to amend 40 CFR 

98.34(c)(6) to allow CGAs to be 

performed using calibration gas 

concentrations of 40–60 percent and 80– 

100 percent of CO2 span, whenever the 

required CO2 span value for a flue gas 

does is not appropriate for the 

prescribed audit ranges in appendix F of 

40 CFR part 60. This will allow CGAs 

to check the response of the CO2

analyzer at two calibration gas 

concentrations, representing separate 

portions of the measurement scale, 


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15TFI’s Comments on the ‘‘Proposed Mandatory 

Reporting of Greenhouse Gases Rule’’ Docket Id. 

No. EPA–HQ–OAR–2008–0508–2376, June 9, 2009. 

Also available in the docket for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424. 

16USEPA Public Hearing for Proposed 

Rulemaking for Mandatory Reporting of Greenhouse 

Gases. Transcript Day One of Two. April 6, 2009. 

Docket Id. No. EPA–HQ–OAR–2008–0508–0212. 

Also available in the docket for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424. 

17The Fertilizer Institute v. EPA, Docket Id. No. 

09–1329 (D.C. Circuit), 2010. Also available in the 

docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

18TFI’s Comments on the Proposed ‘‘2013 

Revisions to the Greenhouse Gas Reporting Rule 

and Proposed Confidentiality Determinations for 

New or Substantially Revised Data Elements,’’ 

Docket Id. No. EPA–HQ–OAR–2012–0934–0036, 

May 2, 2013. Also available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

19Summary of Public Comments and Responses 

for Greenhouse Gas Reporting Rule: 2013 Revisions 

to the Greenhouse Gas Reporting Rule and 

Confidentiality Determinations for New or 

Substantially Revised Data Elements. Docket Id. No. 

Continued 

when the CO2 span is significantly 

lower or higher than 20 percent CO2. 

For the reasons described in section 

II.B.3 of this preamble, the EPA is 

proposing to amend certain provisions 

in 40 CFR 98.36 that require facilities 

with the aggregation of units or common 

pipe configuration types to report the 

annual CO2 mass emissions from the 

combustion of all fossil fuels, per the 

requirements in 40 CFR 98.36(c)(1)(vi) 

and 40 CFR 98.36(c)(3)(vi). The EPA has 

reviewed the data provided under these 

reporting requirements and has 

tentatively concluded that they are no 

longer required for the verification or 

analysis of subpart C annual reports. In 

addition, the reporting of this data for 

the aggregation of units or common pipe 

configuration types has caused 

confusion for reporters because they 

mistakenly believe that the value is used 

in subpart C total CO2 emission 

calculations. Therefore, we are 

proposing to revise the provisions in 40 

CFR 98.36(c)(1)(vi) and 40 CFR 

98.36(c)(3)(vi) to remove the language 

requiring reporting of the total annual 

CO2 mass emissions from all fossil fuels 

combined. 

For these two configuration types 

(aggregation of units and common pipe), 

the reported configuration-level annual 

CO2 emissions from all fossil fuels does 

not factor into any subpart- or facilitylevel total CO2 emission calculations. 

The e-GGRT calculates the subpart-level 

non-biogenic CO2 emissions for these 

two configuration types by summing the 

reported fuel-level CO2 emissions values 

from each fuel, regardless of whether it 

is biogenic or not, then subtracting the 

reported configuration-level biogenic 

CO2 emissions values. For the 

aggregation of units configuration type, 

the reported configuration-level sorbent 

CO2 emissions value, which is typically 

zero, is also added into this ‘‘rolled-up’’ 

non-biogenic CO2 emissions total. The 

calculation was specifically designed in 

this manner because the reported fuellevel information for Table C–1 partially 

biogenic fuels (i.e., tires, MSW) and 

some ‘‘other’’ or ‘‘blend’’ fuels that 

contain biogenic material is not 

sufficient to allow the calculation of 

biogenic CO2 emissions for each fuel 

such that it could be accurately 

subtracted from the fuel-level CO2

emissions values. Thus, the reported 

configuration-level biogenic CO2

emissions must be used in the subpart 

total calculations. Many reporters then 

assume that the configuration-level 

annual CO2 emissions from all fossil 

fuels is also used in the subpart total 

calculations, which creates confusion 

for reporters and has resulted in GHGRP 

Help Desk submissions stating that 

these requirements are redundant and 

confusing. By proposing to revise the 

provisions in 40 CFR 98.36(c)(1)(vi) and 

40 CFR 98.36(c)(3)(vi) to remove the 

language requiring reporting of the total 

annual CO2 mass emissions from all 

fossil fuels combined, we would remove 

this unnecessary confusion for reporters 

with aggregation of units and common 

pipe configuration types. 

C. Subpart G—Ammonia Manufacturing 

For the reasons discussed in section 

II.A.2 of this preamble, we are 

proposing several revisions to subpart G 

of part 98 (Ammonia Manufacturing) to 

improve the quality of the data collected 

from this subpart. Subpart G estimates 

CO2 emissions from ammonia 

manufacturing based on a carbon mass 

balance, which assumes that all carbon 

contained in feedstocks is transformed 

to CO2 and all CO2 is emitted from the 

ammonia manufacturing process. The 

EPA has received numerous comments 

from The Fertilizer Institute (TFI) 

related to the calculation of CO2

emissions from the production of 

ammonia in subpart G. Most comments 

from TFI were related to the carbon 

mass balance methodology, especially 

with regard to other products that could 

be produced using the CO2 emissions 

from ammonia production. TFI has 

asserted that most ammonia 

manufacturing facilities capture and use 

the CO2 resulting from the ammonia 

manufacturing process to produce urea. 

Subpart G does not currently allow the 

subtraction of the CO2 that is bound in 

urea from calculated and reported 

emissions or otherwise allow separate 

reporting of that CO2. 

In response to the 2009 Proposed 

Rule, TFI submitted a comment letter 

dated June 9, 2009, and provided 

comments via a public hearing on April 

6, 2009, stating that the CO2 produced 

through ammonia manufacturing is 

often utilized in the manufacturing of 

urea and that the EPA mistakenly 

assumed that all CO2 in urea will be 

released into the atmosphere.15 16 In 

response, in the 2009 Final Rule, the 

EPA changed the rule requirements to 

collect information on urea production 

and uses of the urea if known, stating 

‘‘Collecting information on urea 

production and its uses will help [the] 

EPA to improve methodologies for 

estimating emissions from ammonia 

manufacturing, urea production and 

urea consumption in the future.’’ 

The EPA next revised 40 CFR 98.72(a) 

and 40 CFR 98.73(b)(5) in subpart G (75 

FR 79092, December 17, 2010) to 

explain that the ‘‘CO2 process emissions 

reported under this subpart may include 

CO2 that is later consumed on site for 

urea production, and therefore is not 

released to the ambient air from the 

ammonia manufacturing process unit.’’ 

This revision was proposed pursuant to 

a settlement agreement with TFI, after 

TFI challenged the 2009 rulemaking.17

In response to an April 2, 2013 EPAproposed rule (78 FR 19802), TFI 

submitted a comment letter dated May 

2, 2013, requesting that the EPA revise 

subpart G to require only the reporting 

of CO2 emitted directly to the 

atmosphere from the synthetic ammonia 

production process instead of 

continuing to include the CO2 captured 

during ammonia production and used to 

produce urea, noting its view that the 

captured CO2 ‘‘does not contribute to 

the CO2 emission estimates for ammonia 

production.’’ 18 TFI further argued the 

existing methodology is inconsistent 

with other source categories covered by 

the rule (namely subpart P (Hydrogen 

Production) and subpart X 

(Petrochemical Production)) and is 

contrary to the EPA’s methodology used 

in the U.S. GHG Inventory. TFI pointed 

to similarities between the structure of 

subpart G and subpart P, and argued 

that the structure of subpart G be 

revised to be more consistent with 

subpart X, which allows sources to 

account for carbon (i.e., subtract from 

direct facility emissions) that is being 

shipped off-site in products. In 

response, the EPA responded that TFI 

had raised a consistency issue within 

part 98 that ‘‘merits evaluation and 

requires further analysis by the EPA.’’ 

However, the EPA explained that no 

changes were made at that time because 

TFI’s comment was outside of the scope 

of the rulemaking.19


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36942 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

EPA–HQ–OAR–2012–0934–0127, November 2013. 

Also available in the docket for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424. 

20TFI’s Comments on the Proposed ‘‘2015 

Revisions and Confidentiality Determinations for 

Data Elements under the Greenhouse Gas Reporting 

Rule,’’ Docket Id. No. EPA–HQ–OAR–2015–0526– 

0064, March 30, 2016. Also available in the docket 

for this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

21TFI, Impact of Federal Regulations on Domestic 

Manufacturing, Docket Id. No. DOC–2017–0001– 

0064, March 31, 2017, available in Compilation of 

Comments Related to the Greenhouse Gas Reporting 

Program submitted to the Department of Commerce 

under Docket ID No. DOC–2017–0001 and the 

Environmental Protection Agency under Docket ID 

No. EPA–HQ–OA–2017–0190 and in the docket for 

this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

22TFI, Comments on ‘‘Evaluation of Existing 

Regulations,’’ Docket Id. No. EPA–HQ–OA–2017– 

0190–40791, May 15, 2017, available in 

Compilation of Comments Related to the 

Greenhouse Gas Reporting Program submitted to 

the Department of Commerce under Docket ID No. 

DOC–2017–0001 and the Environmental Protection 

Agency under Docket ID No. EPA–HQ–OA–2017– 

0190 and in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

In response to a January 15, 2016 

EPA-proposed rule (81 FR 2536), TFI 

submitted a comment letter dated March 

30, 2016, again requesting that part 98 

be made consistent with the 

methodology used in the U.S. GHG 

Inventory, such that CO2 bound in urea 

would not be considered an emission 

from the ammonia manufacturing 

process.20 Also, TFI asked for 

clarification regarding a new 

requirement in subpart G to report the 

amount of methanol produced at the 

ammonia manufacturing facility. In 

response, the EPA noted the potential of 

using a future rulemaking to address 

TFI’s suggested revisions ‘‘to require 

reporting only CO2 that is emitted 

directly to the atmosphere from 

ammonia manufacturing, rather than 

reporting CO2 that is bound in the urea 

that is produced from ammonia at some 

facilities,’’ but explained that the 

comment was outside the scope of that 

rulemaking. The EPA clarified in the 

preamble and in the final rule (81 FR 

89188, December 9, 2016) that the 

quantity of methanol being reported 

only includes methanol that is 

‘‘intentionally produced as a desired 

product’’ and does not include the 

quantity of methanol that is vented or 

destroyed. 

TFI submitted two other comment 

letters in 2017. The letter dated March 

31, 2017 was submitted to the 

Department of Commerce as part of a 

request for information ‘‘Impact of 

Federal Regulations on Domestic 

Manufacturing’’ (82 FR 12786, March 7, 

2017).21 The letter dated May 15, 2017 

was submitted to the EPA’s request for 

comment on ‘‘Evaluation of Existing 

Regulations’’ (82 FR 17793, April 13, 

2017).22 Both letters contained similar 

language asking that the GHGRP be 

amended to ‘‘report the quantity of GHG 

that is actually emitted to the 

atmosphere as part of the manufacturing 

processes’’ instead of ‘‘GHG emissions 

that are captured and either sold or used 

in other industrial processes.’’ 

After consideration of the comments 

from TFI summarized above, the EPA 

has tentatively concluded that requiring 

reporters subject to subpart G to report 

the GHG emissions that occur directly 

from the ammonia manufacturing 

process (i.e., net CO2 process emissions) 

after subtracting out carbon or CO2

captured and used in other products 

would provide a more accurate estimate 

of the emissions and would provide 

consistency in our approach across the 

GHGRP. Therefore, for the reasons 

described in this section and in section 

II.A.2 of this preamble, we are 

proposing multiple amendments to 

subpart G. Under the proposed rule, 

equation G–4 and equation G–5 would 

be combined into a new equation G–4 

and paragraph 98.73(b)(5) would be 

deleted. The reporting requirement in 

paragraph 98.76(b)(1) specifies 

emissions for each individual ammonia 

manufacturing processing unit, so 

determining the combined CO2

emissions from all ammonia 

manufacturing processing units using 

equation G–5 is not necessary for 

reporting. The new equation G–4 would 

allow reporters to subtract CO2 used in 

the production of urea and carbon 

bound in methanol that is intentionally 

produced as a desired product instead 

of assuming that the CO2 bound in urea 

is emitted or that the carbon contained 

in methanol is converted to CO2 and 

emitted, resulting in the calculation of 

net CO2 emissions that occur directly 

from ammonia manufacturing. We are 

also proposing a harmonizing revision 

to the introductory paragraph of 40 CFR 

98.73. These proposed changes are not 

expected to result in an increase in 

burden because the monthly equation 

inputs for the new equation G–4 would 

already be available to calculate the 

annual values of CO2 collected from 

ammonia production and consumed onsite for urea production and the quantity 

of intentionally produced methanol, 

both of which are already reported. 

Similarly, for reporters that do not 

produce urea or methanol, the burden 

under the new equation to calculate CO2

emissions remains unchanged. Further, 

because we are retaining the 

requirement to report the CO2 collected 

from ammonia for urea production and 

methanol production, the proposed 

amendments would not result in any 

negative impacts to the quality of the 

data collected under the GHGRP and 

such data would remain available for 

potential policy evaluation. 

As a result of the new proposed 

equation G–4, two new monthly 

recordkeeping data elements are being 

proposed as part of the verification 

software records required in 40 CFR 

98.77(c), including: (1) quantity of CO2

collected from ammonia production and 

consumed on site for urea production 

each month; and (2) quantity of 

methanol intentionally produced as a 

desired product each month. These 

recordkeeping changes are not expected 

to result in a significant increase in 

burden because both elements are 

already being reported on an annual 

basis (40 CFR 98.76(b)(13) and (15)). For 

reporters that do not produce urea or 

methanol, the requirements for 

recordkeeping remain unchanged. We 

are proposing harmonizing revisions to 

the introductory paragraph of 40 CFR 

98.76 and to the reported data elements 

at 40 CFR 98.76(b)(1) to clarify that 

reporters must provide the ‘‘annual net 

CO2 process emissions’’ for each 

ammonia manufacturing unit, and at 40 

CFR 98.76(b)(13) to clarify that reports 

must provide the ‘‘annual amount of 

CO2 collected from ammonia production 

(metric tons) and consumed on site for 

urea production and the method used to 

determine the CO2 consumed in urea 

production.’’ The proposed revision to 

the reported emissions value excludes 

any CO2 used in the production of urea 

and carbon bound in methanol that is 

intentionally produced as a desired 

product. We are proposing related 

confidentiality determinations for the 

revised data elements, as discussed in 

section VI of this preamble. 

Finally, corresponding amendments 

are being proposed to remove the 

language specified above that was added 

in the 2010 Final Revisions Rule (75 FR 

79092), described above. Paragraph 

98.72(a) will be amended to read, ‘‘CO2

process emissions from steam reforming 

of a hydrocarbon or the gasification of 

solid and liquid raw material, reported 

for each ammonia manufacturing unit 

following the requirements of this 

subpart.’’ 

In addition, minor amendments to 

equation G–1, equation G–2, and 

equation G–3 are being proposed to 

simplify the equations by removing the 

process unit ‘‘k’’ designation in the 

terms ‘‘CO2,G,k,’’ ‘‘CO2,L,k,’’ and 

‘‘CO2,S,k.’’ The introductory paragraph to 

each of these equations already specifies 

that emissions must be calculated for 

each ammonia manufacturing unit. 

Removing the extra subscript will 


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clarify the equations. No changes to 

burden are expected from these changes. 

D. Subpart H—Cement Production 

For the reasons described in section 

II.A.4 of this preamble, we are 

proposing to add new data elements to 

the data reporting requirements for 

subpart H of part 98 (Cement 

Production) to enhance the quality and 

accuracy of the data collected. 

Specifically, we are proposing to collect 

new data elements under 40 CFR 

98.86(a) and 40 CFR 98.86(b). Subpart H 

currently requires calculation of CO2

emissions using one of two 

methodologies, either direct 

measurement using CEMS, or a mass 

balance (non-CEMS) methodology based 

on mass, carbonate content, and fraction 

of calcination for each carbonate-based 

material. For the mass balance method, 

facilities enter input data that is used to 

calculate emissions factors for produced 

materials. These inputs include, for 

example, monthly measurements of 

calcium oxide content and magnesium 

oxide content. Subpart H emission 

equations inputs are not collected under 

the GHGRP, and so the EPA has little 

data on which to build verification 

checks for these inputs in the reporting 

system. In order to improve the data 

verification process, we are proposing to 

collect annual averages for these 

chemical composition input data on a 

facility-basis. The proposed data 

elements (for both facilities that report 

CEMS data and those that report using 

a mass-balance method) include the 

annual arithmetic average weight 

fraction of: total CaO content, noncalcined CaO content, total MgO 

content, and non-calcined MgO content 

of clinker at the facility; and total CaO 

content of cement kiln dust (CKD) not 

recycled to the kiln(s), non-calcined 

CaO content of CKD not recycled to the 

kiln(s), total MgO content of CKD not 

recycled to the kiln(s), and non-calcined 

MgO content of CKD not recycled to the 

kiln(s) at the facility. The proposed data 

elements would rely on an arithmetic 

average of the measurements rather than 

requiring reporters to weigh by quantity 

produced in each month. CEMS facility 

emissions calculations are importantly 

different from non-CEMS emissions 

calculations because combustion and 

process emissions are typically vented 

through the same stack, causing process 

and combustion emissions to be mixed 

and indifferentiable. Therefore, in 

addition to improving the input 

verification process, collecting average 

chemical composition data for CEMS 

facilities will provide the EPA the 

ability to check the reported CEMS 

emission data for accuracy by creating 

the ability to back-estimate process 

emissions. In order to be able to 

estimate and check the accuracy of 

process emissions, we are also 

proposing to collect other data elements 

for both facilities using CEMS and those 

that report using the mass-balance 

method, including annual facility CKD 

not recycled to the kiln(s) in tons and 

raw kiln feed consumed annually at the 

facility in tons (dry basis). Facilities are 

already required to report or maintain 

records of other production data that 

would be needed to perform these 

estimates. Facilities using the massbalance method currently collect CKD 

not recycled to the kiln(s) on a quarterly 

basis to estimate CO2 emissions from 

clinker production. Similarly, facilities 

also record the annual raw kiln feed for 

each kiln, which is used to determine 

the CO2 emissions from raw materials 

for each kiln in equation H–5. The 

proposed data elements would instead 

sum the CKD not recycled and raw kiln 

feed quantity across all kilns at a 

facility. The proposed data elements 

will allow us to estimate process 

emissions for comparison to facility 

reported emissions estimates as a 

verification check. In addition to 

improving verification and data quality 

for cement emissions, the proposed data 

elements will also improve the U.S. 

GHG Inventory. The U.S. GHG 

Inventory can use the proposed data 

elements to internally disaggregate 

process and combustion emissions that 

are reported by facilities using CEMS, 

and create more accurate national-level 

cement emissions profile. 

In general, we do not anticipate that 

the proposed data elements would 

require any additional monitoring or 

data collection by reporters, as these 

data are likely already available in 

existing company records. These 

additions would result in especially 

minimal reporting changes for nonCEMS facilities, as the chemical 

composition averages can be calculated 

using the input data that is already 

required to be entered in the reporting 

system. However, we are requesting 

comment on whether any of the above 

listed data elements would not be 

readily available to reporters. We are 

proposing related confidentiality 

determinations for the additional data 

elements, as discussed in section VI of 

this preamble. 

Finally, for the reasons described in 

section II.A.5 of this preamble, we are 

proposing to clarify equations H–1 and 

H–5. We are proposing to clarify that 

equation H–5 calculates the CO2

emissions from raw materials on a per 

kiln basis. Facilities currently maintain 

records of the amount and organic 

carbon content of raw materials and raw 

kiln feed consumed annually per kiln, 

and enter this data into the e-GGRT 

verification software during submission 

of their annual reports. The verification 

software collects the kiln-level data to 

verify the inputs and generates a file 

containing the records, which are 

specified in 40 CFR 98.87(c)(14) through 

(17). The CO2 emissions for the facility 

are then summed for all kilns at the 

facility-level using equation H–1, which 

sums the annual CO2 emissions from 

clinker production (from equation H–2) 

and the annual emissions from raw 

materials for each kiln (from equation 

H–5). We are proposing revisions to the 

inputs ‘‘rm,’’ ‘‘CO2 rm,’’ and ‘‘TOCrm’’ in 

equation H–5 to clarify that the data 

elements are input on a per-kiln basis, 

and to add brackets to clarify that 

emissions are calculated as the sum of 

emissions from all raw materials or raw 

kiln feed used in the kiln. Similarly, we 

are proposing to revise equation H–1 to 

add brackets to clarify the summation of 

clinker and raw material emissions for 

each kiln, and updating the definition of 

‘‘CO2 rm’’ to clarify the raw material 

input is on a per-kiln basis. The 

proposed revisions are corrections that 

would harmonize equations H–1 and H– 

5 with the existing recordkeeping 

requirements and align the calculation 

methodology in the rule and e-GGRT. 

We are also proposing minor corrections 

to the parameters of equation H–4 for 

quarterly non-calcined CaO content of 

CKD not recycled to the kiln and 

quarterly non-calcined MgO content of 

CKD not recycled to the kiln. The 2009 

final rule inadvertently defined the 

equation parameters for both quarterly 

non-calcined CaO content and quarterly 

non-calcined MgO content as ‘‘CKDCaO’’ 

and ‘‘CKDMgO’’, respectively, while 

equation H–4 defines these parameters 

as ‘‘CKDncCaO’’ and ‘‘CKDncMgO’’. To 

remove any confusion for reporters, we 

are proposing to correct the defined 

parameters for quarterly non-calcined 

CaO content and quarterly non-calcined 

MgO content of CKD not recycled to 

‘‘CKDncCaO’’ and ‘‘CKDncMgO’’, 

respectively. These clarifications would 

not require any changes to the 

monitoring, recordkeeping, or reporting 

provisions, or impact how reporters 

currently collect or enter data for their 

annual reports. 

E. Subpart I—Electronics Manufacturing 

Under subpart I of part 98 (Electronics 

Manufacturing), electronics 

manufacturing facilities must report F– 

GHG and F–HTF emissions from 

electronic manufacturing production 

processes and N2O emissions from 

chemical vapor deposition (CVD) and 


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36944 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

23Fab is defined in 40 CFR 98.98 as ‘‘the portion 

of an electronics manufacturing facility located in 

a separate physical structure that began 

manufacturing on a certain date.’’ 

24The data used to develop the gamma weighting 

factors are also available in the IPCC workbook, 

‘‘Gamma Data Submitted by Industry.xlsx,’’ (2019), 

available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

other electronics manufacturing 

processes. Facilities must also report 

CO2, CH4, and N2O emissions from each 

stationary combustion unit by following 

the requirements of subpart C (General 

Stationary Combustion Sources). 

We are proposing several 

amendments and clarifications to the 

calculation methodologies requirements 

in subpart I. In addition, the EPA is 

proposing conforming changes to the 

reporting and recordkeeping 

requirements of subpart I. Changes 

include updating existing default 

emission factors and destruction or 

removal efficiencies (DREs) based on 

new data, revising certain calculation 

methods, adding a calculation method 

for calculating by-products produced in 

abatement systems, amending data 

reporting requirements, and providing 

clarification on reporting requirements. 

We are proposing revisions that will 

better reflect new industry data and 

current practice, improve the quality of 

the data collected, and streamline the 

reporting requirements. We are also 

proposing related confidentiality 

determinations for the proposed new or 

revised data elements, as discussed in 

section VI of this preamble. 

1. Proposed Revisions To Improve the 

Quality of Data Collected for Subpart I 

a. Revisions To Improve the Calculation 

Methodology for Stack Testing 

We are proposing to revise 40 CFR 

98.93(i), which specifies how to 

calculate GHG emissions based on stack 

testing, in order to improve, simplify, 

and correct the calculation method. As 

discussed in section II.A.2 of this 

preamble, the proposed edits would 

improve the quality of the data 

collection and calculation requirements 

associated with stack testing. First, we 

are proposing to add new equations I– 

24C and I–24D and a table of default 

weighting factors (new Table I–18) to 

calculate the fraction of fluorinated 

input gases exhausted from tools with 

abatement systems, ai,f, for use in 

equations I–19A through I–19C and I– 

21, and the fraction of by-products 

exhausted from tools with abatement 

systems, ak,i,f, for use in equations I–20 

and I–22. Second, we are proposing to 

revise equations I–24A and I–24B, 

which calculate the weighted average 

DREs for individual F–GHGs across 

process types in each fab.23 Third, we 

are proposing at 40 CFR 98.93(i)(3) to 

require that all stacks be tested if the 

stack test method is used. Finally, we 

are proposing to replace equation I–19 

with a set of equations (i.e., equations I– 

19A, I–19B, and I–19C) that will more 

accurately account for emissions when 

pre-control emissions of an F–GHG 

come close to or exceed the 

consumption of that F–GHG during the 

stack testing period. 

The first three changes to the stack 

test method would remove the 

requirements to apportion gas 

consumption to different process types, 

to manufacturing tools equipped versus 

not equipped with abatement systems, 

and to tested versus untested stacks. 

Currently, the fractions of fluorinated 

input gases and by-product gases 

exhausted from manufacturing tools 

with abatement systems, used in 

equations 1–19a through I–22, must be 

estimated by apportioning gas 

consumption to these tools. The 

proposed equations I–24C and I–24D 

would add the option to calculate the 

fraction of each input gas ‘‘i’’ and 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 different per-tool 

emission rates that apply to different 

process types. Facilities would continue 

to have the option to apportion gas 

consumption to tools with and without 

abatement systems by using paragraph 

98.93(e). They would also have the 

option to apportion gas consumption to 

the different process types and subtypes, calculating ai,f and ak,i,f based on 

the numbers of tools with and without 

abatement systems within each process 

type or sub-type. 

Weighting factors are necessary when: 

(1) per-tool pre-control emission rates 

differ between different process types; 

(2) an input gas is consumed by more 

than one process type; (3) the use of the 

input gas is not apportioned between 

the process types; and (4) the fractions 

of tools equipped with emissions 

control technologies differ between 

process types. The weighting factors (gi,p

for input gases and gk,i,p for by-product 

gases, provided in Table I–18) are based 

on data submitted by semiconductor 

manufacturers during the process of 

developing the 2019 Refinement.24 This 

data source was used in lieu of subpart 

I data, as the EPA does not collect data 

on gas consumption or gas consumption 

per tool. The calculated weighting 

factors were within the expected range, 

considering the differences between the 

emission factors used and the expected 

per-tool gas consumption for the 

different process types. For 

microelectromechanical systems 

(MEMS) or PV manufacturing that uses 

semiconductor tools and processes, the 

weighting factors in Table I–18 can be 

used. For processes without a weighting 

factor in Table I–18, a default of 10 must 

be used. More information on the data 

used to develop the weighting factors in 

Table I–18 can be found in the 

document, Technical Support for 

Proposed Revisions to Subpart I (2021) 

(hereafter referred to as ‘‘subpart I 

TSD’’), available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. 

Equations I–24A and I–24B, which 

calculate the weighted average DREs for 

individual F–GHGs across process 

types, would rarely be used if the EPA 

adopts the same default DREs for all 

process types as discussed in section 

III.E.1.b of this preamble, because there 

will rarely be any need to calculate 

weighted average DREs across process 

types in that case. The sole exception 

may occur when a facility uses one or 

more abatement systems with a certified 

DRE value that is different from the 

default to calculate and report 

controlled emissions. To accommodate 

this situation and to simplify equations 

I–24A and I–24B, we are proposing to 

modify equations I–24A and I–24B to 

calculate the average DRE for each input 

gas ‘‘i’’ and by-product gas ‘‘k’’ based on 

tool counts and the same weighting 

factors that would be used in equations 

I–24C and I–24D. This would eliminate 

the requirement to apportion gas 

consumption by process type when 

using the stack test method, even for 

those facilities that use abatement 

systems with different DREs for the 

same input gas ‘‘i’’ or by-product gas 

‘‘k’’. 

Requiring that all stacks be tested (if 

the stack test method is used) would 

remove not only the need to apportion 

gas usage to tested versus untested 

stacks, but also the requirement to 

perform a preliminary calculation of the 

emissions from each stack system (we 

are proposing to remove the 

requirements at 40 CFR 98.93(i)(1)). The 

EPA expects that the data received 

would be more accurate due to requiring 

testing of all stacks. The EPA also 

expects that the revision to measure all 

stacks instead of apportioning gas usage 

between process type and subtype and 

between tested and untested stacks 

would streamline the implementation of 

the stack testing method at facilities and 

increase the likelihood of this method 

being used instead of the emission 

factor approach. Currently, to account 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 36945 

25See Semiconductor Industry Association (SIA) 

Response to EPA’s Stack Test Question 1, March 7, 

2012, and Technical Support for Other Technical 

Issues Addressed in Revisions to Subpart I, U.S. 

EPA, August 2012, both of which are available in 

the docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

for emissions from untested stacks, 

facilities must calculate gas 

consumption of each F–GHG used in 

tools that are vented from untested 

stacks by apportioning gas between 

untested and tested stacks. When 

abatement is used, facilities also 

currently need to apportion by process 

type. Apportioning gas requires using a 

fab-specific engineering model that 

must be based on a quantifiable metric, 

such as wafer passes or wafer starts, or 

direct measurement of input gas 

consumption and must be verified by 

demonstrating its precision and 

accuracy as described in 40 CFR 

98.94(c)(1). As the number of stacks at 

each fab is expected to be small (e.g., 

one to two), the EPA expects that 

measuring all stacks would be more 

accurate and less burdensome than 

developing and verifying an 

apportioning model. 

We also seek comment on whether 

stack testing should also be used to 

estimate N2O emissions if stack testing 

is the calculation method elected. 

Currently, the stack testing option in 

subpart I is limited to estimating 

emissions from F–GHGs; N2O emissions 

must be estimated using the default 

emission factors in Table I–8. The use 

of the stack testing method for N2O was 

not previously recommended by 

industry due to: (1) the high monthly 

and yearly variability in measured N2O 

emission factors estimated from stack 

testing for some fabs; and (2) the 

observation that estimated N2O 

emission factors from stack testing also 

often exceeded 1, indicating a second, 

unidentified, source of N2O.25 No 

source for the additional N2O formation 

or the high variability was identified. 

The EPA requests comment on the 

extent to which the sources of N2O 

formation from electronics 

manufacturing have been identified. We 

are also requesting comment on the 

expected variability of the estimated 

N2O emission factor from stack testing 

if using the current or revised methods 

for estimating emissions using stack 

testing and whether new data are 

available. If estimated N2O emission 

factors are now expected to be 

consistent over time, the use of N2O in 

stack testing could be re-evaluated 

during a future rulemaking. 

We are also proposing to replace 

equation I–19 with a set of equations 

that will more accurately account for byproduct emissions when that by-product 

F–GHG is also an input gas. 

Specifically, the new equations will 

more accurately account for emissions 

when emissions of an F–GHG prior to 

entering any abatement system (i.e., precontrol emissions) would approach or 

exceed the consumption of that F–GHG 

during the stack testing period. Precontrol emissions of an F–GHG can 

approach or exceed consumption of that 

F–GHG when the F–GHG is generated as 

a by-product of other F–GHGs used in 

the fab. To ensure that calculated 

emission factors reflect this physical 

reality, any excess pre-control emissions 

of the F–GHG should be assumed to be 

formed as a by-product. Currently, the 

paragraph containing equation I–19, 40 

CFR 98.93(i)(3)(iii), does not sufficiently 

account for such by-product formation, 

potentially resulting in overestimated 

input gas emission factors and 

underestimated by-product gas emission 

factors. 

This potential inaccuracy arises 

because 40 CFR 98.93(i)(3)(iii), in its 

assignment of portions of the emissions 

to either input gases or by-products, 

does not currently account for the 

utilization (dissociation) of the input gas 

or for any abatement of the input gas. 

Instead, the provision compares the 

total measured emissions of the F–GHG, 

which may have passed through 

abatement systems prior to 

measurement, to the consumption 

(termed ‘‘activity’’ in equation I–19) of 

that F–GHG during the stack testing 

period. If the measured emissions equal 

or exceed consumption, the term for 

total emissions in equation I–19, èsEi,s, 

is equated to consumption to calculate 

the input gas emission factor, and any 

difference between the measured 

emissions of the F–GHG and the 

consumption of the F–GHG is treated as 

by-product emissions and used to 

calculate a by-product emission factor 

(BEF) in equation I–20. While this 

approach avoids assigning a controlled 

emission factor greater than 1.0 to the 

input gas, in cases where the measured 

emissions are greater than consumption, 

the corresponding pre-control emission 

factor is either equal to 1.0 (if the 

measured emissions are uncontrolled) 

or greater than 1.0 (if the measured 

emissions are controlled). In the first 

case, the pre-control emission factor 

fails to account for any utilization of the 

input gas. In the second case, the precontrol emission factor both fails to 

account for any utilization of the input 

gas and attributes emissions to the input 

gas for which the input gas cannot 

possibly be the source (because that 

would violate conservation of mass). 

To more accurately assign emissions 

of the gas to by-product or input gas 

emissions, a better methodology is to 

compare the measured emissions to the 

maximum expected controlled 

emissions of the input gas during the 

stack testing period, rather than to the 

consumption during that period. To 

make this change, we are proposing to 

remove equation I–19 and replace that 

equation with equations I–19A, I–19B, 

and I–19C, making corresponding 

changes to 40 CFR 98.93(i)(3)(iii). 

Equation I–19A estimates the maximum 

expected controlled emissions for each 

F–GHG from the fab during the stack 

testing period at a utilization rate (U) 

equal to 0.2 (i.e., a 1–U or input gas 

emission factor of 0.8) and at the levels 

of abatement and abatement system 

uptime observed during the stack testing 

period. If the total emissions measured 

during the stack testing period are less 

than the maximum expected controlled 

emissions calculated using I–19A, then 

all emissions of gas i are attributed to 

the consumption of gas ‘‘i’’ and equation 

I–19B is used to calculate the input gas 

emission factor for gas ‘‘i’’. Equation I– 

19B is similar to equation I–19 in the 

current rule, but with an updated 

process-independent variable for the 

DRE. However, if the total measured 

emissions are greater than the estimate 

of the maximum controlled emissions, 

then the input gas emission factor is 

assumed to be equal to the maximum 

controlled emission rate at an uptime 

equal to 1, as calculated in equation I– 

19C. The remaining emissions (the 

difference between the measured 

emissions and the value calculated in 

equation I–19A) are used to calculate 

the BEF for that gas from other input 

gases in equation I–20. 

The revised equations improve upon 

the current equations because they 

account both for any control of the 

emissions and for some utilization of 

the input gas. The input gas emission 

factor (1–U) of 0.8 used in equations I– 

19A and I–19C is the same as the default 

1–U factor that would be assigned 

where a default is not available in 

Tables I–3 and I–4, as discussed in 

III.E.2.b of this preamble. Using a value 

of 0.8 as a maximum input gas emission 

factor (1–U) would be consistent with 

the other proposed changes and is 

expected to increase the accuracy of the 

stack testing method, as some utilization 

of the input gas is expected. These 

changes to the stack testing equations 

would improve the quality of the stack 

testing method by more accurately 

assigning emissions to their source. 

In addition to the substantive changes 

to equation I–19, the EPA is proposing 

to clarify the definitions of the variables 


jspears on DSK121TN23PROD with PROPOSALS2
36946 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

26See Volume 3, Chapter 6. Electronics Industry 

Emissions to the 2019 Refinement to the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories, as cited above in this document. 

dif and dkif, the average DREs for input 

gases and by-product gases respectively, 

in equations I–19A, I–19B, I–19C, and I– 

19D, in equations I–20 through I–22, in 

equations I–24A and B, and in equation 

I–28 of subpart I. Currently, the 

definition for the variable dif reads 

‘‘Fraction of fluorinated GHG input gas 

i destroyed or removed in abatement 

systems connected to process tools in 

fab f,’’ which could be interpreted to 

reflect both the fraction of emissions of 

gas i that is fed into abatement systems 

and the fraction of gas i that is destroyed 

once gas i is fed into abatement systems. 

However, dif (and dkif) are only intended 

to reflect the fraction of gas i (or byproduct gas k) that is destroyed once gas 

i (or by-product gas k) is fed into 

abatement systems. To make this clear, 

we are proposing to change the 

definition of dif to read ‘‘Fraction of 

fluorinated GHG input gas i destroyed 

or removed when fed into abatement 

systems by process tools in fab f,’’ and 

we are proposing a parallel change to 

the definition of dkif. 

b. Revisions To Clarify and Revise 

Calculation Methodologies and 

Required Data Elements for Data 

Submitted in the Technology 

Assessment Report 

For the reasons described in section 

II.A.1 of this preamble, we are 

proposing to require that three emission 

factor calculation methods, specified in 

this section and described in the subpart 

I TSD (available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424), be used when 

calculating utilization and by-product 

emission rates submitted in technology 

assessment reports. These three 

methods would be used to report the 

results of each emissions test. Based on 

a comparison among the results of the 

three methods, we may ultimately 

require use of a single method through 

a future rulemaking. 

As stated in the preamble to the 2013 

final rule that established the 

requirement to submit technology 

assessment reports (78 FR 68175, 

November 13, 2013), one of the EPA’s 

goals in collecting emission factor data 

through the reports is to better 

understand how emission factors may 

be changing as a result of technological 

changes in the semiconductor industry, 

and whether the changes to the 

emission factors may justify further data 

collection to comprehensively update 

the default emission factors in Tables I– 

3 and I–4. To meet this goal, the 

emission factors submitted in the 

technology assessment reports should 

be calculated the same way as the 

emission factors already in the EPA’s 

database were calculated; otherwise, 

differences attributable to differences in 

calculation methods may amplify or 

obscure differences attributable to 

technology changes. To date, the EPA 

has not initiated a broad data collection 

to comprehensively update the default 

emission factors, but the EPA is now 

proposing to use the emission factor 

data submitted in the 2017 and 2020 

technology assessment reports to make 

minor updates to the default emission 

factors, and the EPA may continue this 

practice in the future. This introduces a 

second goal for the emission factors 

submitted in the technology assessment 

report, which is that they be robust to 

ensure that the resulting updated 

default emission factors are robust. To 

meet this goal, the reported emission 

factors should be broadly applicable 

because they reflect physical reality as 

much as possible and are not unduly 

affected by changing proportions of 

input gases. In addition, the reported 

emission factors should be consistently 

calculated across facilities and 

processes to ensure that the resulting 

defaults are not biased by ‘‘cherrypicking’’ of methods to achieve a 

desired result for a given process or 

facility (or set of processes or facilities). 

Requiring facilities to (1) use specified 

methods to calculate emission factors 

and (2) use all three methods for each 

test meets these goals to different 

extents and in different ways. 

Requiring facilities to use specified 

emission factor calculation methods 

would ensure that the emission factors 

are robust insofar as the calculation 

methods are designed to yield robust 

factors. It would also help ensure that 

the emission factors are developed in a 

reasonably, though not perfectly, 

consistent manner across processes and 

facilities and over time, given that the 

proposed calculation methods are 

similar but not identical. (As discussed 

in this section, two of the proposed 

emission factor calculation methods are 

based closely on the emission factor 

calculation methods used for the 

emission factors already in the EPA’s 

database.) The EPA has previously 

received emission factors calculated via 

a variety of methods, as described 

further in this section. This has 

sometimes made it difficult to 

determine whether changes in 

calculated emission factors are due to 

changes in technology or to changes in 

the emission factor calculation method. 

In some cases, we have not been able to 

use submitted emission factor data 

because it was found to be calculated 

using a method that was significantly 

different from previous methods and 

that appeared unlikely to represent 

actual gas behavior. (The lead authors of 

the Electronics chapter of the 2019 

Refinement declined to use this data for 

similar reasons.) 26 Specifying emission 

factor calculation methods would at 

least partially address these problems. 

Requiring facilities to submit three 

sets of emission factors for each test 

would more fully address these 

problems by enabling us: (1) to directly 

compare the new emission factor data to 

the emission factor data that is already 

in the EPA’s database and that was 

calculated using the same method; and 

(2) to compare the results across the 

available emission factor calculation 

methods and to identify any systematic 

differences in the results of the different 

methods for each gas and process type. 

By identifying and quantifying 

systematic differences in the results of 

the different methods, we would be 

better able to distinguish these 

differences from differences attributable 

to technology changes. This would 

enable us to build a bridge between the 

data sets resulting from the different 

methods, which would be useful in the 

event that we ultimately required 

facilities to submit emission factors 

using one method only, particularly if 

that method was not one of the methods 

used historically. We would also be able 

to evaluate how much the results of 

each method varied for each gas and 

process type; high variability may 

indicate that the results of a method are 

being affected by varying input gas 

proportions rather than differences in 

gas behavior, as discussed further in this 

section. Ultimately, these analyses 

would enable us to more accurately 

characterize emissions from 

semiconductor manufacturing by 

selecting the most robust emission 

factor data for updating the default 

emission factors in Tables I–3 and I–4. 

Because we plan to incorporate the 

three methods into spreadsheets that 

would calculate three sets of emission 

factors based on a single set of entered 

data, we do not anticipate that requiring 

reporting of the results of the three 

methods would significantly increase 

burden. We are proposing the three 

emission factor calculation methods in 

40 CFR 98.96(y)(2)(iv)(A) through (C). 

Two of the proposed methods are 

closely based on the methods that have 

been used historically to calculate 

emission factors for processes that use 

multiple gases: ‘‘all-input gas method’’ 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 36947 

27See section 2.0 of the document, Technical 

Support for Modifications to the Fluorinated 

Greenhouse Gas Emission Estimation Method 

Option for Semiconductor Facilities under Subpart 

I (2012), available in the docket for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424). 

28Previously, the EPA had suggested that the allinput gas method be used for etch emission factors 

(Ibid.), and most of the etch data in the data set used 

to develop the current emission factors used this 

method (see 78 FR 68185 and previously submitted 

data sets Etch Process Equipment Emissions 

Characterization Data and International 

SEMATECH Manufacturing Initiative 

Environmental Safety and Health Technology 

Center, February 2012, and the document Draft 

Emission Factors for Refined Semiconductor 

Manufacturing Process Categories (2010), all 

available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424). However, some 

of this data was calculated using the dominant gas 

method. 

29As discussed further in the document 

Technical Support for Modifications to the 

Fluorinated Greenhouse Gas Emission Estimation 

Method Option for Semiconductor Facilities under 

Subpart I, cited above in this section, trends in gas 

usage, such as the use of more and more individual 

input gases, may introduce apparent, but not real, 

trends in the 1–U values calculated using these 

methods. 

and the ‘‘dominant gas method’’.27 28

Consequently, the emission factors 

calculated using these methods are 

generally expected to be comparable to 

the emission factors calculated and 

submitted to the EPA in the past. The 

emission factors calculated using these 

methods are also expected to be 

reasonably robust except under certain 

circumstances discussed further in this 

section. To increase the robustness of 

the emission factors calculated using 

these methods under those 

circumstances, we are proposing to 

modify the methods to avoid input gas 

emission factors greater than 0.8 for 

processes that use multiple gases. 

Historically, both the all-input gas 

and dominant gas methods have 

calculated the input gas emission rate in 

the same way: all emissions of each F– 

GHG that is an input gas have been 

attributed to the 1–U factor for that gas 

(kg of input gas emitted/kg of input gas 

used); that is, both methods imply that 

if an F–GHG is used as an input gas, that 

F–GHG is not also formed as a byproduct. However, the two methods 

treat by-product F–GHGs that are not 

used as input gases differently. The 

dominant gas convention assigns all 

emissions of F–GHG by-products to the 

carbon-containing F–GHG input gas 

accounting for the largest share by mass 

of the input gases (kg of by-product 

emitted/kg of dominant gas used), while 

the all-input gas convention assigns 

emissions of F–GHG by-products to all 

F–GHG input gases (kg of by-product 

emitted/kg of all F–GHGs used). With a 

slight modification, the all-input 

convention has also been used to assign 

emissions of F–GHG by-products to only 

all carbon-containing F–GHG input 

gases, i.e., not to SF6 or NF3 input gases 

(kg of by-product emitted/kg of all F– 

GHGs used). 

Due to the complex set of chemical 

reactions necessary to describe plasma 

etching by multiple input gas processes, 

it is not generally known what fractions 

of a by-product gas are produced by 

each input gases, or what fractions of an 

emitted input gas consist of unreacted 

residual gas versus newly formed byproducts of other gases. Both methods of 

assigning emission factors described 

above have historically been based on 

the assumption that the emissions of 

each input gas (1–U) are much larger 

than the emissions of the same gas as a 

by-product of the other input gases (e.g., 

CF4 produced from C2F6) and thus, the 

BEF can be approximated as zero. 

However, as stated in section III.E.1.c of 

this preamble on updates to the default 

emission factors, it has been well 

established that most input gases 

produce CF4 and C2F6 in significant 

quantities. Thus, in cases where C2F6 or 

CF4 is an input gas (and possibly for 

some additional cases), assigning all of 

the emissions of C2F6 or CF4 to the C2F6

or CF4 input gas, respectively, may not 

be a good approximation and can lead 

to cases where the reported emission 

factor is greater than 1, which violates 

conservation of mass. This is most likely 

to happen when an input gas such as 

CF4 makes up a relatively small share of 

the total input gas mass and is also 

generated in significant quantities as a 

by-product by the other input gases. 

To address this issue, our proposed 

methods include a modification to both 

of the historically recommended 

methods to avoid an input gas emission 

factor greater than 0.8 when multiple 

gases are used, and we are also 

proposing to introduce an additional 

calculation method. The modified 

methods would attribute emissions of 

each F–GHG used as an input gas to that 

input gas until the mass emitted equaled 

80 percent of the mass fed into the 

process, that is, until the 1–U factor 

equaled 0.8. The methods would then 

assign the remaining emissions of the F– 

GHG either to the dominant input gas as 

a by-product (in the dominant gas 

method) or to the other input gases as 

a by-product in proportion to the 

quantity of each input gas used in the 

process (in the all-input gas method). 

This approach avoids violating 

conservation of mass and better reflects 

the expectation that at least a small 

portion of the input gas will be utilized 

in the process. Nevertheless, because 0.8 

represents an upper bound for input gas 

emission factors, even the modified 

methods have the potential to 

significantly overestimate input gas 

emission factors. To the extent that 

these factors are later applied to 

processes where the input gas accounts 

for a larger share of the total input gas 

mass (e.g., because they are used to 

calculate default factors), they will 

overestimate emissions of the input gas. 

A third convention, the reference 

emission factor method, is likely to 

provide more robust, realistic results, 

although it represents a somewhat larger 

change from the emission factor 

calculation conventions historically 

used. The reference emission factor 

method begins with the average input 

gas utilizations (1–U factors) and/or 

BEFs observed based on single gas 

recipes. In single-gas recipes, all 

emissions of an input gas clearly 

originate from its use as an input gas, 

and all emissions of a by-product clearly 

originate from its generation as a byproduct; thus, the 1–U factor and BEFs 

based on single-gas recipes are not 

affected by the uncertainties regarding 

the origins of the emissions that can 

affect these factors for multi-gas recipes. 

Since it is not known whether the 1– 

U factor or BEFs are more likely to 

change in moving from single- to 

multiple-gas recipes, the reference 

emission factor method calculates 

emissions using the 1–U and the BEFs 

that are observed in single gas recipes 

and then adjusts both factors based on 

the ratio between the emissions 

calculated based on the factors and the 

emissions actually observed in the 

multi-gas process. This approach uses 

all the information available on 

utilization and by-product generation 

rates from single-gas recipes while 

avoiding assumptions about which of 

these are changing in the multi-gas 

recipe. 

In summary, the chief advantage of 

the dominant gas method proposed at 

40 CFR 98.96(y)(2)(iv)(A) and the allinput gas method proposed at 40 CFR 

98.96(y)(2)(iv)(B) is that they are the 

methods used previously to calculate 

the emission factors that are already in 

the EPA’s database and that form the 

basis of the current subpart I default 1– 

U and BEFs. Therefore, new emission 

factors calculated using these methods 

are expected to be comparable 29 to the 

emission factors already in the EPA’s 

database, facilitating efforts to identify 

changes in emission factors that are 

attributable to technology changes. The 

chief disadvantage of these two methods 

is that they can result in a significantly 

overestimated 1–U value when the share 

of an input gas such as CF4 declines. 


jspears on DSK121TN23PROD with PROPOSALS2
36948 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

30See document Technical Support for Proposed 

Revisions to Subpart I (2021), available in the 

docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

This disadvantage is mitigated partly, 

but not completely, by capping 1–U 

values at 0.8. At the same time, 

however, capping 1–U values at 0.8 

decreases the comparability of these 

methods with those previously used to 

calculate and report emission factors. 

The EPA requests comment on whether 

the gain in robustness achieved by 

capping 1–U values at 0.8 justifies the 

accompanying loss in comparability to 

previously submitted data, particularly 

given that we are proposing to require 

submission of results using both the 

historically used methods and the new, 

likely more robust, reference emission 

factor method. The reference emission 

factor method is being proposed at 40 

CFR 98.96(y)(2)(iv)(C). The advantages 

and disadvantages of the three methods 

are described further in the document 

Technical Support for Modifications to 

the Fluorinated Greenhouse Gas 

Emission Estimation Method Option for 

Semiconductor Facilities under Subpart 

I, cited above in this section. The EPA 

also considered requiring use of one 

specific method for the data submitted 

in future technology assessment reports. 

This would allow all future reports to 

have comparable data. However, if one 

of the historically used methods were 

specified, the resulting emission factors 

might not be as robust as they would be 

if the reference emission factor method 

were specified. On the other hand, if the 

reference emission factor method were 

specified, the resulting emission factors 

would not be fully consistent with 

previously submitted emission factors, 

and this inconsistency would be 

difficult to address without having seen 

the results of the different methods sideby-side at least once. Another option 

would be to let the reporter choose one 

of three methods in 40 CFR 

98.96(y)(2)(iv)(A) through (C) for 

subsequent reports. This option would 

result in a loss of comparability between 

tests. The EPA is requesting comment 

on these alternatives. 

We request comment on the methods 

proposed at 40 CFR 98.96(y)(2)(iv)(A) 

through (C) for calculating emission 

factors for multi-gas recipes, particularly 

concerning their reliability as indicators 

of actual emission rates and emission 

rate trends. In addition, the EPA 

requests comment on the use of 0.8 as 

the maximum 1–U value in the 

modified dominant-gas and all-input gas 

methods. 

We also request comment on the 

reference emission factor method 

proposed at 40 CFR 98.96(y)(2)(iv)(C). 

While this method differs from the 

historically used methods, the 

differences are not expected to become 

important except where CF4 or C2F6

make up a small share of the input gas 

mass, that is, where the historically 

used methods are known to yield 

inaccurate results. The EPA believes 

that the increase in accuracy gained 

through the new method justifies some 

loss of time series consistency (i.e., 

comparability between newly submitted 

emission factor data and previously 

submitted emission factor data). 

Moreover, because we are proposing to 

require reporting of the results of each 

test using all three calculation methods, 

we can compensate for the loss of time 

series consistency between the 

historically used methods and the 

reference emission factor method by: (1) 

comparing the emission factors already 

in the EPA’s database to the versions of 

the new emission factors calculated 

using the historically used methods (i.e., 

the all-input gas and dominant gas 

methods); and (2) analyzing systematic 

differences that occur between the 

results of the historically used methods 

and of the reference emission factor 

method so that these can be considered 

in future comparisons between new and 

existing data. We also request comment 

on whether BEFs based on multi-gas 

recipes should be included in the 

reference BEFs for the reference 

emission factor method. The benefit of 

including BEFs based on multi-gas 

recipes in the reference BEFs is that this 

would increase the number of data 

points used as a basis for those BEFs, in 

some cases providing reference BEFs 

where none are available from the single 

gas data set (due to a lack of data). The 

drawback of including BEFs based on 

multi-gas recipes is that these BEFs are 

subject to some uncertainty. BEFs 

measured for multi-gas recipes where 

the by-product F–GHG is not also used 

as an input gas are less uncertain than 

BEFs where the by-product F–GHG is 

also an input gas. However, uncertainty 

remains regarding which of the multiple 

input gases are primarily responsible for 

the formation of that by-product and 

whether all input gases contribute to the 

formation of each by-product. For more 

information on the advantages and 

disadvantages of using only single-gas 

measurements or all measurement to 

determine reference emission factors see 

the subpart I TSD, cited above in this 

section. 

We also seek comment on whether 

there are alternative methods for 

calculating utilization and by-product 

formation rates that the EPA should 

consider in the future. To enable us to 

evaluate any suggested methods, we 

request that commenters suggesting an 

alternative method also provide 

information on the rationale for using 

the alternative method instead of one of 

the methods described above and a 

comparison between a representative 

group of emission factors (both 1–U and 

BEFs) calculated using the alternative 

method and a group of emission factors 

based on the same data but calculated 

using the all-input gas method, the 

dominant gas method, and the reference 

emission factor method. The EPA may 

evaluate, at a future date, such 

alternative methods based, for example, 

on the likely accuracy of the alternative 

calculation method and its consistency 

with previously used calculation 

methods.30

We are also proposing that where 

reporters provide any data on utilization 

and by-product formation rates in the 

technology assessment report, they must 

also specify the method used to 

calculate the reported utilization and 

by-product formation rates and assign 

and provide an identifying record 

number for each data set. This 

information allows the EPA to better 

understand the data being submitted. 

For example, this information helps the 

EPA identify all the gases used in a 

multi-gas test and understand the 

influence of the calculation method and 

gas mixtures on the resulting emission 

factors. This detailed understanding 

may help us to develop new or revised 

emission factors that are representative 

of the industry. Without collecting these 

data, the EPA may not be able to 

effectively evaluate the influence of 

different emission factor calculation 

methods or gas combinations on the 

resulting emission factors. 

We are also proposing at 40 CFR 

98.96(y)(2)(iv) that for any destruction 

or removal efficiency (DRE) data 

submitted, the report must include 

whether the abatement system used for 

the measurement is specifically 

designed to abate the gas measured 

under the operating condition used for 

the measurement. This information will 

help the EPA understand whether the 

submitted data should be considered to 

be a result for a certified abatement 

system for the gas being measured. The 

efficacy of abatement systems generally 

depends on both whether it is designed 

to abate the F–GHG and whether it is 

installed, operated, and maintained 

according to the manufacturer’s 

specifications. Abatement systems are 

known to have reduced efficacy when 

the individual process gas and total gas 

flow rates (including any added purge 


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31Available in ‘‘UPDATED Appendix A Process 

Emissions Characterization Data,’’ Semiconductor 

Industry Association, April 2018, and ‘‘2020 

Subpart I Consolidated Triennial Report, 

Appendices A–B,’’ Semiconductor Industry 

Association, March 2020, available in the docket for 

this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

32The data submitted in previous years can be 

found in Semiconductor Industry Association; Etch 

Process Equipment Emissions Characterization 

Data, International SEMATECH Manufacturing 

Initiative Environmental Safety and Health 

Technology Center, February 2012, and Draft 

Emission Factors for Refined Semiconductor 

Manufacturing Process Categories, Office of Air and 

Radiation, May 2010, each of which is available in 

the docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

33See Technical Support Document for Process 

Emissions from Electronics Manufacture (e.g., 

Micro-Electro-Mechanical Systems, Liquid Crystal 

Displays, Photovoltaics, and Semiconductors): 

Proposed Rule for Mandatory Reporting of 

Greenhouse Gases, Revised, November 2010, 

available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

gases) as specified by the abatement 

system supplier are exceeded. 

c. Updates to Default Emission Factors 

and Destruction or Removal Efficiencies 

To Improve the Accuracy of Emissions 

Estimates 

The EPA is proposing to update the 

default emission factors and destruction 

or removal efficiencies (DREs) in 

subpart I based on new data submitted 

as part of the 2017 technology 

assessment report (submitted with the 

RY2016 annual report) and the 2020 

technology assessment report 

(submitted with the RY2019 annual 

report).31 First, we are proposing to 

update the utilization rates and BEFs for 

F–GHGs used in semiconductor 

manufacturing in Tables I–3, I–4, I–11 

and I–12 to reflect new data received in 

the 2017 and 2020 technology 

assessment reports, to correct errors 

identified in the data set on which the 

current default emission factors are 

based, and to remove BEFs where both 

the emission factor and the GWP of the 

emitted by-product are very low. 

Second, we are also proposing to update 

and expand the default emission factors 

for N2O used in all electronics 

manufacturing in Table I–8 based on 

both new data from the 2017 and 2020 

technology assessment reports and new 

emission factors available in the 2019 

Refinement. Third, we are proposing at 

40 CFR 98.93(a)(6) to revise the 

utilization rate and BEF values assigned 

to gas/process combinations where no 

default utilization rate is available. 

Finally, we are proposing to update the 

default DREs in Table I–16 to reflect the 

incorporation of new data from the 2017 

and 2020 technology assessment reports 

and a new approach to abatement 

system certification. These updates are 

expected to increase the accuracy of the 

emissions reported by facilities under 

subpart I. 

The proposed emission factors for 

Tables I–3, I–4, I–11, and I–12 were 

calculated from measured data 

submitted by U.S. semiconductor 

manufacturers as part of the 2020 

technology assessment report, 2017 

technology assessment report, and data 

collected in previous years.32 The total 

data set contains 4,358 input gas and 

BEFs across all commonly used gas and 

process type combinations, with 1,506 

of these data points newly available via 

the 2020 and 2017 triennial technology 

assessment report. All the data 

submitted via the 2020 and 2017 

triennial technology assessment report 

were applicable to the 300-mm wafer 

size. All data sets were reviewed for 

errors, including, but not limited to, 

transcription errors and violations of the 

fluorine balance. Calculated emission 

factors (1–U or BEFs) greater than 1.00 

(a total of 18 data points) were excluded 

from the calculation of the proposed 

default emission factors (EFs). Input gas 

and by-product gas emission factors 

were also analyzed for each test to see 

whether the fluorine balance was 

violated. This resulted in the exclusion 

of 40 data points from the calculation of 

the proposed default emission factors. 

There were also a small number of 

transcription or other errors, including 

duplicate rows of data, that were 

corrected or excluded prior to 

calculating the proposed emission 

factors. Transcription and other errors 

resulted in the exclusion of 33 data 

points. A single reported by-product 

value for SF6 was also excluded from 

the calculation, as there was no source 

of sulfur. Four emission factors for NF3

in remote plasma cleaning (RPC) 

processes that were previously 

excluded 33 were re-included in the data 

set, as discussed in the subpart I TSD, 

available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. 

Submitted data were also reviewed for 

methodological consistency with 

previously submitted data. As discussed 

earlier in III.E.1.b of the preamble, data 

submitted to the EPA prior to 2017 used 

either the dominant gas or all-input gas 

convention. However, many of the data 

points for etching submitted as part of 

the 2020 and 2017 technology 

assessment report used an alternative 

convention that had not been previously 

used. This new ‘‘multi-gas’’ convention 

differed in how it assigned emissions of 

input gases. Instead of assigning 

measured emissions of an input gas 

entirely to the input gas, emissions of an 

input gas were assigned to all input F– 

GHGs used in the process by dividing 

the measured mass emitted of a specific 

input gas by the total mass of all input 

F–GHGs and assigning this emission 

factor to each input F–GHG as either the 

1–U factor or the by-product factor, i.e., 

all input F–GHGs were considered to 

equally contribute to the emissions of 

each input gas. This method was 

inconsistent with the methods of the 

previous data set, and the alternative 

method often resulted in large increases 

to the reported BEFs and concurrently 

large decreases to the reported 1–U. 

This change appeared to be largely a 

result of the change in methodology; 

however, it was not possible, based on 

the data received, to fully assess the 

effect of the new methodology as the 

data were not directly comparable to 

previously submitted data. The data 

points that were affected by the change 

in convention were excluded from the 

calculation of the proposed default EFs, 

resulting in the exclusion of 338 data 

points. This left a total of 3,951 data 

points in the combined data set that 

were included in the calculations of the 

proposed default emission factors in 

Tables I–3 and I–4. 

The proposed default EFs for Tables 

I–3 and I–4 were calculated using a 

simple arithmetic mean of all EF data 

that used either the all-input gas or the 

dominant gas convention. The 

technology assessment reports reported 

no major changes to semiconductor 

production technology, and the 

differences between the average 

emission rates calculated based on the 

new and previously submitted data, 

respectively, are generally small (i.e., 

less than ± 20 percent for most 

commonly used input gases). Therefore, 

it is assumed in most cases that the 

proposed default emission factors for F– 

GHGs reflect increased and/or improved 

data rather than changes in actual 

emission or utilization rates. This means 

that for each wafer size (<200 mm and 

300 mm), the proposed emission factors 

are generally likely to represent 

emission rates over all the years of the 

GHGRP. However, for a few gas and 

process type combinations for the 300- 

mm wafer size, the differences between 

the averages calculated based on the 

new and previously submitted data are 

more significant and could have an 

appreciable impact on the overall 

calculated CO2e emissions. More 

information on the differences between 

the data contained in the two 

technology assessment reports received 

to-date and the previously submitted 

data is available in the subpart I TSD, 


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34More information regarding the development of 

the proposed default emission factors can be found 

in the workbook titled, ‘‘Data sets Supporting 

Revised Emission Factors.xlsx,’’ (U.S. EPA, April 

2020) and in the subpart I TSD, available in the 

docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

35See Volume 3, Chapter 6. Electronics Industry 

Emissions to the 2019 Refinement to the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories, as cited above in this document. 

36 GHGRP data from RY2013 was used for this 

analysis as it is the last year for which it is was 

relatively simple to estimate gas consumption due 

to revisions to the default emission factors applied 

in 2014 and later. For more information on how gas 

consumption was estimated, see U.S. EPA. 

Inventory of Greenhouse Gas Emissions and 

Sinks:1990–2017 (2019). https://www.epa.gov/ 

ghgemissions/inventory-us-greenhouse-gasemissions-and-sinks-1990-2017. 

37Chamber cleaning processes, which typically 

use only one input gas, are not expected to generate 

carbon-containing byproducts from that input gas 

unless either the input gas or the film being 

removed contains carbon. The situation with 

etching and wafer cleaning processes, where 

multiple input gases are often used, is more 

complex. This is because input gases that do not 

contain carbon can still contribute fluorine to 

carbon-containing F–GHG by-products that obtain 

their carbon from other input gases, particularly if 

relatively fluorine-rich and carbon-poor byproducts such as CF4 predominate. The data set 

supporting the default emission factors proposed in 

this action includes by-product emission factors 

that have sometimes been calculated assuming that 

carbon-containing by-products are attributable to all 

input gases (including those lacking carbon) and 

that have other times been calculated assuming that 

carbon-containing by-products are only attributable 

to input gases that contain carbon. 

available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. In light of these 

findings, we request comment on 

whether the new data reflect recent 

technology changes or simply better 

represent technologies that have been in 

use over the long term (i.e., at least since 

2011, the first year of reporting under 

the GHGRP). This is important for 

understanding the time period to which 

the new data for these four factors are 

applicable. 

We are also proposing to update the 

calculation methodology for MEMs and 

PV manufacturing to allow use of 40 

CFR 98.3(a)(1), the current methodology 

for semiconductor manufacturing, in 

lieu of using 40 CFR 98.3(a)(2) for 

manufacture of MEMs and PV using 

semiconductor tools and processes. This 

would have the effect of applying the 

default emission factors in Tables I–3 

and I–4 to these processes. In the 2019 

Refinement, use of semiconductor 

default emission factors for MEMs 

manufacturing is recommended when 

using semiconductor tools to 

manufacture MEMs. Similarly, we are 

also proposing the use of semiconductor 

emission factors for PV manufacturing 

that uses semiconductor manufacturing 

tools. It is expected that the use of 

semiconductor emission factors will 

result in more accurate emissions 

estimates when semiconductor 

manufacturing tools and processes are 

used. 

The current Table I–8 does not 

distinguish N2O emission factors either 

by the type of electronic device 

manufactured (semiconductor versus 

LCD) or by wafer size. Due to the 

increased availability of N2O emission 

factor data, we are proposing to update 

Table I–8 to include distinct utilization 

rates for N2O for semiconductor 

manufacturing and LCD manufacturing 

and, for semiconductor manufacturing, 

utilization rates by wafer size (<200 mm 

and 300 mm) and by process type.34 The 

proposed emission factor for N2O used 

in CVD thin film deposition for LCD 

manufacturing can be found in the 2019 

Refinement.35 Currently there is no LCD 

manufacturing in the United States and 

thus, no U.S. data is available for LCD 

manufacturing. 

We are also proposing to remove BEFs 

from Tables I–3 and I–4 where there is 

a combination of both a low BEF and a 

low GWP, resulting in very low reported 

emissions per metric ton of input gas 

used (<0.03 mtCO2e and less than 

0.0002 percent of emissions (in CO2e) 

per metric ton of input gas consumed). 

This would result in: (1) removing the 

BEFs for C4F6 and C5F8 for all input 

gases used in wafer cleaning or plasma 

etching processes due to the 

combination of a low GWP (0.003 and 

1.97, respectively) and low BEFs (less 

than 0.009); and (2) not adding BEFs for 

COF2 and C2F4 for any input gas/process 

combination from the new data received 

in the 2020 or 2017 technology 

assessment reports because these BEFs 

are less than 0.2 and COF2 and C2F4

have low GWPs (0.14 and 0.004, 

respectively). COF2 does not have a 

chemical specific GWP in Table A–1 (it 

is currently assigned a default GWP of 

2000 as an ‘‘Other Fluorinated GHG’’), 

but the 2018 WMO Scientific 

Assessment listed the 100-year GWP of 

COF2 as ‘‘<1.’’ We calculated a precise 

GWP for COF2 of 0.14 using the 

atmospheric lifetime and radiative 

efficiency provided in the 2018 WMO 

Scientific Assessment. (The method we 

used to calculate the GWP of COF2 was 

the method we used to calculate precise 

GWPs for low-GWP compounds in the 

most recent update to GHGRP GWPs (79 

FR 73750, December 11, 2014)). 

Currently, Table I–3 lists the BEF for 

C4F6 from all input gases as ‘NA’. 

Similarly, Table I–4 currently lists the 

BEF for C5F8 from all input gases as 

‘NA’. Thus, for these two cases, there 

will be no change in reported emissions. 

Data reported to the GHGRP in 2013 36

indicates that, in total, for all 

semiconductor manufacturers reporting 

to the GHGRP in 2013, by-product 

emissions of C5F8 and C4F6 totaled 0.27 

and 0.0004 mtCO2e, respectively. 

Similarly, it is estimated that based on 

2013 gas consumption COF2 and C2F4

by-product emissions for the 

semiconductor fabs reporting to the 

GHGRP in 2013 would have been 0.43 

mtCO2e and 0.005 mtCO2e, respectively, 

if COF2 and C2F4 emission factors were 

adopted. For the largest fabs, generation 

of all by-products listed above whose 

emission factors are being proposed for 

removal or exclusion from Tables I–3 

and I–4 would result in less than 0.6 

mtCO2e in combined emissions per fab 

and significantly less for smaller fabs. 

We are also proposing to modify the 

applicability of carbon-containing BEFs 

to chamber cleaning process subtypes 

where neither the input gas(es) nor the 

films being processed by the chamber 

contain carbon. In the emission factor 

tables in subpart I (e.g., Table I–3 and 

I–4), there are cases where a 

perfluorocarbon BEF is provided even 

when the input gas i does not contain 

carbon (e.g., NF3). However, when none 

of the input gases contain carbon (e.g., 

NF3 or SF6), and when the chamber 

being cleaned does not process films 

that contain carbon, then neither CF4

nor other carbon-containing gases are 

expected to be formed during the 

process.37 Thus, we are proposing that 

in cases where neither the input gas nor 

the films being processed in the tool 

contain carbon, the BEF for the carboncontaining by-products be set to zero 

(refer to variable ‘‘Bkij’’ in proposed 

equation I–8B). We are proposing to 

apply this provision at the process 

subtype level; a BEF of zero would only 

be used for a combination of input gas 

and chamber cleaning process subtype 

(e.g., NF3 in RPC) if no carboncontaining materials were removed 

using that combination of input gas and 

chamber cleaning process subtype 

during the year and no carboncontaining input gases were used on 

those tools. Otherwise, the default BEF 

would be used for that combination of 

input gas and chamber cleaning process 

subtype for all of that gas consumed for 

that subtype in the fab for the year. An 

alternative approach would be to 

implement this change at the individual 

process or tool level, tracking gas 

consumption used in processes and 

tools that deposit films that contain 

carbon. This would lead to a more 

precise estimate of carbon-containing 

by-product emissions but may require 


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38For more information on the development of 

the proposed emission factors for Tables I–11 and 

I–12, see the explanation for the equivalent Tier 2b 

tables in the subpart I TSD in the docket for this 

rulemaking (Docket Id. No. EPA–HQ–OAR–2019– 

0424). 

39U.S. EPA 2019. Available at https://

www.epa.gov/ghgemissions/inventory-usgreenhouse-gas-emissions-and-sinks-1990-2017. 

40For more information, see ‘‘Technical Support 

for Accounting for Destruction or Removal 

Efficiency for Electronics Manufacturing Facilities 

under subpart I,’’ (August 2012) prepared for the 

Final Amendments and Confidentiality 

Continued 

greater apportioning than is otherwise 

required by the rule. We request 

comment on this alternative approach. 

Whether this revision was implemented 

at the process subtype or process level, 

it would improve the accuracy of the 

emissions estimate compared to the 

current rule by differentiating between 

process subtypes (or processes) where 

there is a source of carbon from which 

carbon-containing by-products may be 

generated and process subtypes (or 

processes) where there is no source of 

carbon from which carbon-containing 

by-products may be generated. 

In addition, we are proposing to 

update the default emission factors for 

semiconductor manufacturing for use 

with the stack test method (Tables I–11 

and I–12). These tables will continue to 

be needed to calculate emissions from 

consumption of each intermittent lowuse F–GHG as defined in 40 CFR 98.98. 

The proposed default emission factors 

for Tables I–11 and I–12 were developed 

using the same data used to calculate 

revised emissions factors for Tables I–3 

and I–4, as discussed above. To 

calculate the proposed default emission 

factors for Tables I–11 and I–12, which 

are process-independent, gas 

consumption by process type and wafer 

size was first estimated from emissions 

data reported under subpart I for 

RY2013. Gas consumption by process 

type was then used to weight the 

process-dependent emission factors 

from Tables I–3 and I–4 to arrive at the 

proposed default emission factors for 

Tables I–11 and I–12, respectively. Gas 

consumption by process type was used 

as a weighting factor to arrive at 

process-independent emission factors in 

order to have default emission factors 

that represent the average emission 

factor over total gas consumption by the 

industry for each wafer size.38 Although 

the proposed emission factors proposed 

in this rulemaking differ slightly from 

the 2019 Refinement due to the 

inclusion of newly available data, the 

methodology for developing Tables I–11 

and I–12 are the same as those used to 

develop the Tier 2b tables in the 2019 

Refinement. For more information on 

the EPA’s method for estimating gas 

consumption from emission data 

reported under subpart I for RY2013, 

which was used in the 2019 Refinement, 

see the Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990–2017.39

The workbook ‘‘Data Sets Supporting 

Revised Emission Factors’’ also shows 

the calculations for deriving the 

emissions factors in Tables I–11 and I– 

12 from Tables I–3 and I–4 (available in 

the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424). 

We are requesting comment on three 

options regarding default emission 

factors for MEMS and PV 

manufacturing. One option is to allow 

MEMS and/or PV manufacturers to use 

either the current default emission 

factors for those sub-sectors in Tables I– 

5 (MEMS) and I–7 (PV) or the default 

emission factors for semiconductor 

manufacturing in Tables I–3 and I–4, as 

applicable. The second option is to 

remove Tables I–5 and I–7 from subpart 

I and to require MEMS and/or PV 

manufacturers to use the default 

emission factors in Tables I–3 and I–4, 

as applicable. The third option is to 

continue to require MEMS and PV 

manufacturers to use the default factors 

in Tables I–5 and I–7, respectively. 

Information gathered during the 

development of the 2019 Refinement 

and through the GHGRP indicates that 

the emission factors for semiconductor 

manufacturing in Tables I–3 and I–4, as 

applicable, are often, and perhaps 

always, applicable to MEMS and PV 

manufacturing. (In the 2019 Refinement, 

semiconductor default emission factors 

are applied to MEMS manufacturing 

that is ‘‘carried out using tools and 

processes similar to those used to 

manufacture semiconductors.’’) 

However, we request comment on the 

extent to which semiconductor 

manufacturing default emission factors 

are applicable to MEMS and PV 

manufacturing. We also request 

comment on whether the distinction 

between different wafer sizes that 

separates Table I–3 from Table I–4 is 

applicable to MEMS and/or PV 

manufacturing. 

We are also proposing to revise the 

input gas and BEF values assigned to 

gas/process combinations where no 

default input gas emission factor is 

available (due to a lack of data) in 40 

CFR 98.93(a)(6). Currently, if no default 

input gas emission factor is available for 

a particular gas/process combination, 

reporters must use a general default 

value of one for the input gas emission 

factor (i.e., a utilization rate of zero) and 

a general default value of zero for the 

BEFs. This assumes that emissions 

equal consumption, i.e., all gas used in 

a process is emitted, without any 

utilization or conversion into other 

gases. However, in the majority of cases 

where emission factor data are available, 

both CF4 and C2F6 are emitted as byproducts, and both CF4 and C2F6 are 

long-lived GHGs with very high GWPs 

(see Table A–1). Where the input gas 

has a GWP similar to those of PFCs, 

accounting for the generation of CF4 and 

C2F6 by-products is not expected to 

significantly change the GWP-weighted 

emissions calculated for the process 

compared to the current method, but 

where the input gas has a GWP 

significantly lower than those of PFCs, 

accounting for the generation of the byproducts would considerably improve 

the estimate of GWP-weighted 

emissions compared to the current 

method. In both cases, accounting for 

the likely emissions of CF4 and C2F6

would also lead to a better estimate of 

each species emitted. Thus, we propose 

to revise the general defaults where no 

default input gas emission factor is 

available to account for the likely partial 

conversion of the input gas into CF4 and 

C2F6. Specifically, for a gas/process 

combination where no default input gas 

emission factor is available in Tables I– 

3, I–4, I–5, I–6, and I–7, we are 

proposing at 40 CFR 98.93(a)(6) that 

reporters would use an input gas 

emission factor (1–U) equal to 0.8 (i.e., 

a default utilization rate or U equal to 

0.2) with BEFs of 0.15 for CF4 and 0.05 

for C2F6. It is assumed here in cases 

where data do not exist, that the input 

gas is partially converted into CF4 and 

C2F6 during the process and the 

remainder is emitted. The default input 

gas emission factor is conservatively 

based on the least efficient gas in Table 

I–4 for etch processes (C2F6 in the 

revised Table I–4). The remainder of the 

input gas is assigned to CF4 and C2F6. 

Due to a generally higher CF4 BEF for 

most input gas/process combinations, 

the majority (75 percent) of the 

remaining mass is assigned to CF4. 

Additionally, we are proposing to 

update the default DREs in Table I–16 

to reflect the incorporation of new data 

from the 2017 and 2020 technology 

assessment reports and a new approach 

to abatement system certification. 

Currently, Table I–16 to subpart I lists 

default DREs by gas and process type. 

Where data were unavailable for some 

gas and chamber cleaning process 

combinations, DRE values were set to a 

conservative value of 60 percent in the 

current tables.40 Commenters have 


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Determination for Electronics Manufacturing Final 

Rule (78 FR 68162, November 13, 2013), available 

in the docket for this rulemaking, Docket Id. No. 

EPA–HQ–OAR–2019–0424. 41See data sets ‘‘UPDATED–04–02–2018- 

Triennial Report Data for EPA,’’ ‘‘Attachment B. 

New and Revised DRE Test Used in SIA Analysis 

of Alternative Default DREs’’ from Comments of the 

SIA on the Greenhouse Gas Reporting Program: 

Proposed Amendments and Confidentiality 

Determinations for Subpart I (Docket Id. No EPA– 

HQ–OAR–2011–0028–0095), and ‘‘Etch DRE 

Testing With Flow Data, March 6, 2012,’’ [2020 

Triennial Data set]. All are available in the docket 

for this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

42S.N. Li, et al. ‘‘FTIR spectrometers measure 

scrubber abatement efficiencies,’’ Solid State 

Technology, Vol. 45. (2002); Gray, Fraser, and 

Afroza Banu, ‘‘Influence of CH4-F2 mixing on CF4

by-product formation in the combustive abatement 

of F2,’’ Research Disclosure, Sept. 2018, both 

available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

43See Volume 3, Chapter 6. Electronics Industry 

Emissions to the 2019 Refinement to the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories, as cited above in this document. 

previously noted that where 

exceptionally conservative DREs exist, 

there is a large incentive to invest in 

measuring site-specific DREs. Based on 

the measured data received by the EPA, 

the EPA is proposing to assign 

chemical-specific DREs to all commonly 

used F–GHGs for the semiconductor 

manufacturing sub-sector without 

distinguishing between process types.41

We are proposing to revise the default 

DREs in Table I–16 by incorporating 

new data received via the 2017 and 

2020 technology assessment reports. 

The proposed DREs were calculated 

using a simple arithmetic mean of all 

DRE data by gas. The DRE data sets 

submitted to the EPA by the U.S. 

electronics manufacturing industry, 

including both data received via the 

technology assessment reports and 

previously submitted data, contains 

1,353 data points for DREs of F–GHGs 

(for a discussion on DREs for N2O, see 

the subpart I TSD, available in the 

docket for this rulemaking, Docket Id. 

No. EPA–HQ–OAR–2019–0424). Of 

these, 58 of the data points 

corresponded to gases that are not 

known to be input gases or significant 

by-products (C2F4 and COF2, see 

previous discussion on emission factors 

excluded from Tables I–3 and I–4). 

Thus, we are not proposing default 

DREs in Table I–16 for these gases. Data 

points were not included in the 

calculations of the proposed DREs if the 

data points were reported as 

corresponding to emissions control 

systems that were not certified to abate 

that particular gas. Additional data 

points were excluded from the 

calculations of the proposed DREs if an 

accurate DRE could not be measured 

due to detection limits. Negative DREs 

were also excluded from the calculation 

for all F–GHGs. All but two of the 

negative DREs submitted for F–GHGs 

were on emissions control devices that 

were not designed to abate that 

particular gas. For the two cases where 

the system was designed to abate the 

gas, the testers noted either low gas inlet 

or inherent noise in the measurement 

(e.g., due to low inlet). For the DREs 

from systems recorded as not designed 

or certified to abate the input gas, the 

negative DREs were reported only for 

CF4 and COF2. Results from literature 42

indicate that CF4 can be formed within 

some emission control systems that use 

hydrocarbon fuels by reaction between 

the fuel and fluorinated species (e.g., F2) 

emitted from a NF3 remote plasma 

chamber clean. All but one of the 

negative CF4 DREs are from remote 

plasma chamber cleaning processes. 

However, since not all abatement 

systems form CF4, these data points 

were excluded from this analysis and 

this formation of CF4 is accounted for 

separately in the proposed rule. Data 

points were also excluded from the 

calculation if the gas being measured 

was noted as being less than two 

percent of the total inlet fluoride to the 

abatement system during testing, as the 

error in measuring DREs for such low 

inlet concentrations may have biased 

the DREs low. It is also known in the 

industry that when extremely low 

concentrations (e.g., 100 ppm) of F– 

GHGs in the abatement system are 

present, the system is less efficient at 

destroying the F–GHG. Including these 

DREs in an unweighted average would 

have a disproportionate effect on the 

estimated emissions. Lastly, additional 

data points were excluded if the 

abatement system required maintenance 

or repair (e.g., due to fouling of the 

system due to poor water quality), or the 

abatement system was operated in a 

manner inconsistent with the 

manufacturer’s recommendations (e.g., 

using clean dry air (CDA) instead of O2

as the oxidant, as is recommended by 

the manufacturer). The data sets include 

data for most gas-process combinations. 

The EPA also considered using the 

DREs published in the 2019 

Refinement.43 However, some of the 

data included in the 2019 Refinement 

are not available to the EPA due to 

confidentiality concerns. Thus, the EPA 

was only able to determine how this 

subset differed on average to the EPA 

data sets. The confidential data set had 

higher average DREs for most F–GHGs. 

This may be due to fact that this subset 

contained DREs as measured by 

abatement system manufacturers and 

may not be representative of actual fab 

conditions. The EPA has also received 

additional data via the 2020 technology 

assessment report that was not available 

during the development of the 2019 

Refinement. The most recent data set 

received from industry via the 2020 

technology assessment report included a 

significant number of DRE values that 

were significant outliers. Many of these 

outliers were excluded due to the 

reasons discussed above. The EPA 

considered excluding additional data 

points from the DRE calculations for 

Table I–16 but did not have enough 

information to determine whether the 

data points were representative of fab 

operating conditions, due to abnormal 

conditions, or due to operating the 

abatement system outside of 

manufacturer specifications. The EPA is 

requesting comment on the conditions 

under which data points were measured 

and whether any correspond to 

conditions that were atypical or outside 

of the manufacturer’s recommendation 

for operation of the abatement system. 

The DREs in the proposed rule include 

data from the 2020 and 2017 technology 

assessment reports and earlier data sets. 

As discussed above, all DRE data points 

from the technology assessment reports 

from abatement systems designed to 

abate the F–GHG input gas were 

included in the calculations of the 

proposed default DREs except in cases 

where: (1) the DRE was negative; (2) 

there were detection limit issues; (3) the 

inlet gas flow of the F–GHG measured 

was less than 2 percent of the inlet gas; 

(4) the abatement system required 

maintenance or repair; or (5) the 

abatement system was operated in 

manner inconsistent with the 

manufacturer’s specifications. The 

subpart I TSD, available in the docket 

for this rulemaking, Docket Id. No. 

EPA–HQ–OAR–2019–0424, describes 

the full data set and the default DREs 

considered, including the option of 

excluding significant outliers. Where 

data for gas-process combinations still 

do not exist (or there were less than 5 

data points), there are sufficient data 

across the various gas/process 

combinations to assign DREs based on 

analogy with gases with similar 

chemical structures. The revised Table 

I–16 also includes proposed DREs for 

C2HF5, C5F8, and C4F8O based on their 

similarity to CHF3 (for C2HF5 and C5F8) 

and c-C4F8 (for C4F8O). This results in 

C2HF5 and C5F8 being assigned a default 

DRE of 97 percent. Based on its 

similarity to c-C4F8, C4F8O is assigned a 

default DRE of 93 percent. The EPA is 

proposing to base the DRE for C3F8 on 

the DREs for a chemically similar F– 

GHG for which the EPA does have data. 


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Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 36953 

44The 98-percent DRE for C3F8 in the current rule 

was assigned by analogy with C2F6, which also has 

an assigned DRE of 97 percent in the current rule 

(78 FR 68192, November 13, 2013). 

45More information on the EPA’s analysis of the 

DRE data can be found in the subpart I TSD and 

supporting documents (‘‘Combined DRE data 

sets.xlsx’’) in the docket for this rulemaking (Docket 

Id. No. EPA–HQ–OAR–2019–0424). 

46 Id. 

47S.N. Li, et al. ‘‘FTIR spectrometers measure 

scrubber abatement efficiencies,’’ Solid State 

Technology, Vol. 45. (2002); Gray, Fraser, and 

Afroza Banu, ‘‘Influence of CH4-F2 mixing on CF4

by-product formation in the combustive abatement 

of F2,’’ Research Disclosure, Sept. 2018, both 

available in this docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

C3F8 is expected to be no more difficult 

to abate than C2F6. Thus, the EPA is 

proposing to apply the DRE value for 

C2F6 (98 percent) to C3F8. A value of 98 

is slightly higher than the DRE for C3F8

in the current rule (97 percent).44 45

Since the data does not show 

statistically significant differences 

between process types,46 we are 

proposing to remove the distinction by 

process type from Table I–16. In 

addition, we are proposing to equate the 

default DRE for each F–GHG to the 

straight average of the measured DREs 

for that F–GHG rather than setting the 

default DRE slightly below the average. 

The DREs currently in Table I–16 were 

developed using analysis of variance 

(ANOVA), which took into account the 

likely variations in abatement device 

performance across fabs and within a 

single fab (see the memorandum, Final 

Technical Documentation—Revision of 

Default Utilization Rates and ByProduct Formation Rates; Revision of 

Default Destruction and Removal 

Efficiencies for Semiconductor Facilities 

under subpart I; and Revision of 

Maximum Field Detection Limits for the 

Stack Test Method (Alexis McKittrick, 

U.S. EPA, August 16, 2013), which was 

used in the development of the 2013 

Final Rule (78 FR 68182, November 13, 

2013) and is available in the docket for 

this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424). A conservative 

approach was used because the DRE 

performance of abatement equipment 

can vary depending on the specific 

design of each manufacturer, which is 

often proprietary, and the actual 

conditions in the fab. However, here, we 

are proposing a more refined method for 

estimating controlled emissions that 

would still account for variability across 

manufacturers. 

To account for the variations in 

device performance, we are proposing to 

modify the conditions under which the 

default DRE can be claimed. Currently, 

in 40 CFR 98.94(f), in order to claim the 

defaults provided in Table I–16, 

abatement equipment must be certified 

as specifically designed for F–GHG or 

N2O abatement, and the abatement 

system must be certified as being 

properly installed, operated, and 

maintained according to the site 

maintenance plan for abatement 

systems. Site maintenance plans must 

also be based on the manufacturer’s 

recommendations and specifications. 

The EPA is proposing to clarify the 

definition of operational mode in 40 

CFR 98.98 to specify that operational 

mode means that the system is operated 

within the range of parameters as 

specified in the DRE certification 

documentation. Thus, the abatement 

system should only be considered 

operational and the default or certified 

lower DRE claimed when the system is 

operated within the range of parameters 

for which the system is certified to meet 

or exceed the claimed DRE. The 

specified parameters must include a 

range of total F–GHG or N2O flows and 

total gas flows (with N2 dilution 

accounted for) through the emissions 

control systems. For systems operated 

outside the range of parameters 

specified in the documentation 

supporting the DRE certification (e.g., 

with total flows exceeding the original 

equipment manufacturer (OEM) 

specifications), a site-specific DRE could 

be measured and claimed. The system 

could then be considered operational 

within the range of parameters used to 

develop a site-specific DRE. We are also 

proposing to modify the conditions in 

40 CFR 98.94(f) under which the default 

DRE may be claimed to require that the 

reporter, in order to claim the default 

value for that abatement system and gas, 

must: (1) certify that the abatement 

device is able to achieve a value equal 

to or greater than the default DRE value 

under the worst-case flow conditions 

during which the facility is claiming 

that the system is operational; and (2) 

provide supporting documentation. 

Worst-case flow conditions would be 

defined as the highest total F–GHG or 

N2O flows through each model of 

emissions control systems (gas by gas 

and process type by process type across 

the facility) and the highest total flow 

scenarios (with N2 dilution accounted 

for) across the facility during which the 

emission control system is claimed to be 

operational. The certification would be 

based on testing of the abatement 

system model by the abatement system 

manufacturer using a scientifically 

sound, industry-accepted measurement 

methodology that accounts for dilution 

through the abatement system, such as 

the Protocol for Measuring Destruction 

or Removal Efficiency (DRE) of 

Fluorinated Greenhouse Gas Abatement 

Equipment in Electronics Manufacturing 

(March 2010) (EPA 430–R–10–003, 

hereinafter ‘‘EPA DRE Protocol,’’ 

available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424). If the equipment is 

certified to abate the F–GHG or N2O but 

at a value lower than the default DRE, 

facilities would not be able to claim the 

default; however, facilities would be 

allowed to claim the lower 

manufacturer verified value. Sitespecific measurements by the 

electronics manufacturer would still be 

required to claim a higher DRE than the 

default. The updated DREs reflect 

increased data and a refined approach 

rather than changes in the actual 

destruction rates. The updates to the 

DREs in Table I–16 would increase the 

accuracy of emissions reported by 

facilities and would be expected to 

reduce the number of facilities that 

choose to measure site-specific DREs. 

d. Calculation of By-Products Produced 

in Hydrocarbon Fueled Abatement 

Systems To Improve the Accuracy of 

Emissions Estimates 

We are proposing to add a calculation 

methodology that would estimate the 

emissions of CF4 produced in 

hydrocarbon-fuel based emissions 

control systems that are not certified not 

to generate CF4. (In this section III.E.1.d, 

all references to ‘‘uncertified 

hydrocarbon-fuel based emission 

control systems’’ refer to hydrocarbonfuel based emissions control systems 

that are not certified not to generate 

CF4.) The proposed calculation would 

be codified in equation I–9; we are 

proposing to renumber the previous 

equation I–9 as equation I–8b. 

Hydrocarbon-fuel based emission 

control systems are hydrocarbon-fuel 

based combustion devices that are 

designed to reduce emissions from 

exhaust streams from electronics 

manufacturing processes and include, 

but are not limited to, abatement 

systems that are designed to abate F– 

GHGs or N2O. Studies have shown that 

direct reaction between molecular 

fluorine (F2) and hydrocarbons (e.g., 

CH4) to form CF4 can occur in 

hydrocarbon-fueled combustion 

emissions control systems, and the 2019 

Refinement includes calculations to 

account for the formation and emission 

of CF4 from this source.47 Where 

emissions control systems that generate 

CF4 are used to abate NF3 from RPC 

processes, the CF4 is expected to 

account for 1.5 times the emissions of 

NF3 (in CO2e) that would have occurred 

with no abatement (see the subpart I 


jspears on DSK121TN23PROD with PROPOSALS2
36954 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

48See Volume 3, Chapter 6. Electronics Industry 

Emissions to the 2019 Refinement to the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories, as cited above in this document, and 

the subpart I TSD (available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424). 

49The by-product emission factor for F2 from NF3

was calculated from 15 measurements of remote 

plasma clean processes following a variety of 

different Thin Film Deposition (TFD) processes. F2

generation was estimated using a mass-balance 

approach that compared the mass of atomic fluorine 

(F) flowing into each process chamber in the form 

of NF3 with the mass of fluorine exiting the process 

chambers in the form of SiF4, COF2, HF, and NF3. 

The mass of fluorine that was not accounted for at 

the exhaust of the process chamber was assumed to 

be in the form of F2. 

50The by-product emission factor for F2 from NF3

was calculated from 15 measurements of remote 

plasma clean processes following a variety of 

different Thin Film Deposition (TFD) processes. F2

generation was estimated using a mass-balance 

approach that compared the mass of atomic fluorine 

(F) flowing into each process chamber in the form 

of NF3 with the mass of fluorine exiting the process 

chambers in the form of SiF4, COF2, HF, and NF3. 

The mass of fluorine that was not accounted for at 

the exhaust of the process chamber was assumed to 

be in the form of F2. 

51All documents in the docket are listed at 

https://www.regulations.gov. Although listed in the 

index, some information is not publicly available, 

e.g., CBI or other information whose disclosure is 

restricted by statute. 

TSD available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424). 

Equation I–9 would be used to 

estimate the emissions of CF4 from 

generation in emissions control systems 

by calculating the mass of the fluorine 

entering uncertified hydrocarbon-fuel 

based emissions control systems (the 

product of the consumption of the input 

gas, the emission factor for fluorine, and 

ai, where ai is the ratio of the number 

of tools with uncertified abatement 

devices for the gas-process combination 

to the total number of process tools for 

the gas-process combination) and 

multiplying that mass by a CF4 emission 

factor, ABCF4,F2. The proposed default 

emission factor for this reaction 

(ABCF4,F2) is 0.116.48 This reaction is 

expected to result in significant 

emissions only where F2 is used as an 

input gas or where large amounts of F2

can be formed as a by-product of the 

decomposition of the cleaning gas into 

atomic fluorine and subsequent 

recombination of the unreacted fluorine 

into F2. Thus, this equation would only 

apply to processes that use F2 as an 

input gas or to RPC processes that use 

NF3 as an input gas. When NF3 is used 

as a cleaning gas during the RPC 

process, the vast majority of the NF3

molecules (approximately 98 percent, 

based on the default values for (1– 

UNF3,RPC)) are decomposed within the 

remote plasma unit to form fluorine and 

nitrogen radicals, ions, and excited 

species. While some of the fluorinated 

species clean the solid residues 

deposited on the chamber walls by 

combining with the residues to form 

gaseous by-products such as SiF4, HF, 

COF2, and CF4, some fluorine atoms 

recombine to form molecular fluorine 

(F2). Based on confidential data received 

from Edwards, Ltd.,49 a manufacturer of 

abatement equipment, the proposed BEF 

for F2 from NF3 used in remote plasma 

clean processes is 0.5. This data was 

also used to update the 2019 

Refinement. The proposed by-product is 

reasonable considering that emission 

factor data for NF3 from RPC processes 

submitted to the EPA show that 

emissions of NF3 and CF4 accounted for 

less than 20 percent of the total mass of 

fluorine in the NF3 used in the process 

in all but one of the 123 processes 

measured, and generally significantly 

less, leaving at least 80 percent of the 

fluorine available to form F2, SiF4, and 

HF. (The last two compounds are 

formed when fluorine combines with 

solid residue on the chamber walls, but 

the EPA’s emission factor data do not 

include specific information on the 

quantities of those compounds—or of 

the fluorine—formed in the process.) No 

data from processes that use F2 as an 

input gas are currently available for the 

1–U of F2; however, data from NF3-using 

processes (where most of the NF3 is 

dissociated into atomic fluorine during 

the process) indicate that the 1–U value 

for F2 may be near 0.7 (Confidential data 

received from Edwards, Ltd.,50 2018, 

available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424).51

As for other gas and process 

combinations where no data is available 

(listed as ‘‘NA’’ in Tables I–3 and I–4), 

a 1–U of 0.8 would be used for F2 in 

equation I–9 for all process types. The 

EPA is seeking comment on whether 

there is data available to support an 

alternative 1–U for F2. The addition of 

this calculation is expected to increase 

the accuracy of emissions estimates 

from electronics manufacturers that use 

emissions control equipment. Along 

with the new calculation, we are 

proposing corresponding monitoring, 

reporting, and recordkeeping 

requirements (see 40 CFR 98.94(e), 40 

CFR 98.96(o), and 40 CFR 98.97(b), 

respectively) for facilities that: (1) use 

hydrocarbon-fuel-based emissions 

control systems to control emissions 

from tools that use either NF3 as an 

input gas in RPC processes or F2 as an 

input gas in any process; and (2) assume 

in equation I–9 that one or more of those 

systems do not form CF4 from F2. These 

proposed provisions, which are 

patterned after the current provisions 

covering abatement systems from which 

facilities quantify emission reductions, 

would require that the facility certify 

and document that the model for each 

of the systems that the facility assumes 

does not form CF4 from F2 has been 

tested and verified to produce less than 

0.1 percent CF4 from F2, and that each 

of these systems is installed, operated, 

and maintained in accordance with the 

directions of the emissions control 

system manufacturer. The facility could 

perform the testing itself, or it could 

supply documentation from the 

emissions control system manufacturer 

that supports the certification. If the 

facility performed the testing, it would 

be required to measure the rate of 

conversion from F2 to CF4 using a 

scientifically sound, industry-accepted 

method that accounts for dilution 

through the abatement device, such as 

the EPA DRE Protocol, adjusted to 

calculate the rate of conversion from F2

to CF4 rather than the DRE. The EPA 

requests comment on whether there are 

other measurement methods that should 

be cited as examples or listed as options 

for this measurement. The EPA has 

considered that it may be difficult to 

adapt the EPA DRE Protocol to measure 

the rate of conversion from F2 to CF4 if 

the analytical methods cited in the 

Protocol (Fourier Transform Infrared 

(FTIR) and Quadrupole Mass 

Spectroscopy (QMS)) do not work well 

to measure F2 flows. Instead, other 

measuring or metering methods, such as 

calibrated mass-flow controllers or 

electrochemical cells, may be more 

effective. The EPA requests comment on 

this and any other issues that may arise 

in adapting the EPA DRE Protocol to 

measure the rate of conversion from F2

to CF4 in hydrocarbon-fuel-based 

emissions control systems. These issues 

and means of handling them could then 

be specifically addressed in the final 

rule. 

Given the potential sensitivity of a 

calculated stack emission factor to any 

emissions of CF4 produced in 

hydrocarbon-fuel based emissions 

control systems, we are also proposing 

to amend paragraph 40 CFR 

98.94(j)(1)(i) to require that the uptime 

(i.e., the fraction of time that abatement 

system is operational and maintained 

according to the site maintenance plan 

for abatement systems) during the stack 

testing period average at least 90 percent 

for uncertified hydrocarbon-fueled 

emissions control systems. This would 

ensure that the calculated stack 

emission factor for CF4 will not be 

underestimated due to a significant 

fraction of uncertified systems not 


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Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 36955 

52See Volume 3, Chapter 6. Electronics Industry 

Emissions to the 2019 Refinement to the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories, as cited above in this document. 

operating during the stack test. This 

proposed amendment is similar to the 

current requirement in 40 CFR 

98.98(j)(1)(i), which requires at least 90 

percent uptime averaged over all 

abatement systems during the stack 

testing period, but would now require 

that this specific set, hydrocarbonfueled abatement systems that are not 

certified not to generate CF4, also 

average at least 90 percent uptime 

during the test. 

Because CF4 may be formed from F2

in any hydrocarbon-fuel-based 

emissions control system, not only 

abatement systems from which facilities 

claim reductions for purposes of 

reporting under subpart I, we are 

proposing to apply these provisions to 

all hydrocarbon-fuel-based emissions 

control systems used in electronics 

manufacturing facilities. This includes, 

but is not limited to, abatement systems 

as defined at 40 CFR 98.98. We are 

proposing to add a definition of 

‘‘hydrocarbon-fuel-based emissions 

control system’’ to clarify the scope of 

coverage. 

e. Revisions to Calibration Requirements 

for Abatement Systems 

We are proposing to modify 40 CFR 

98.97(d)(9)(ii) to require that a vacuum 

pump’s purge flow indicators are 

calibrated every time a vacuum pump is 

serviced or exchanged. Some vacuum 

pumps’ purge flow indicators are 

inaccurate and could deliver higher 

than indicated purge flow, exceeding 

the manufacturer’s maximum flow 

specification for an abatement system.52

Requiring calibration of the vacuum 

pumps would make it less likely that 

facilities would unknowingly claim an 

abatement system as operational during 

a time period when the abatement 

system is being operated outside of the 

manufacturer’s flow specifications. 

Operating outside of the manufacturer’s 

flow specifications is problematic 

because abatement systems are generally 

certified to meet or exceed the claimed 

DRE only when operated within a 

specified range of flow. We expect that 

this requirement would require 

calibrations every 1 to 6 months, 

depending on the process. The EPA is 

requesting comment on whether this 

approach and expected frequency is 

recommended or an approach that 

specifies the frequency of calibration, 

such as a minimum calibration of twice 

a year, would be a sufficient approach 

to maintain accurate flow rates. 

2. Revisions To Streamline and Improve 

Implementation for Subpart I 

a. Revisions to the Applicability 

Calculations for Subpart I 

As discussed in section II.B.1 of this 

preamble, we are proposing to revise the 

applicability of subpart I. We are 

proposing to do this by adding a second 

option in 40 CFR 98.91(a) for estimating 

GHG emissions for semiconductor, 

MEMS, and LCD manufacturers; by 

revising the current applicability 

calculation for PV manufacturers; and 

by updating the emission factors used in 

the current applicability calculations for 

MEMS and LCD manufacturers. 

Currently, semiconductor, MEMS, and 

LCD manufacturers that have not 

previously reported under the GHGRP 

are required to calculate the subpart I 

contribution toward the 25,000 mtCO2e 

reporting threshold by using a 

calculation based on annual 

manufacturing capacity in substrate area 

(square meters, m2). The calculation 

based on manufacturing capacity was 

adopted in part to limit the burden 

required for facilities to estimate their 

electronics manufacturing emissions for 

purposes of assessing the applicability 

of the GHGRP, as this method does not 

require either tracking gas consumption 

or apportioning gas consumption by 

process type. Instead, it is based on 

production capacity in terms of 

substrate area and default emission 

factors based on manufacturing type. 

However, this method may not be 

suitable for some facilities that have 

emissions per m2 rates that are atypical 

and could consequently require some 

facilities that emit considerably less 

than 25,000 mtCO2e (unabated) to report 

under the GHGRP. 

We are therefore proposing to add a 

second option for estimating emissions 

in 40 CFR 98.91(a)(1) and (2) that 

includes two new equations, I–1B and 

I–2B (and renumbering equations I–1 

and I–2 to I–1A and I–2A, respectively). 

Specifically, we are proposing to add an 

optional calculation method that uses 

gas consumption multiplied by a simple 

set of emission factors (along with 

GWPs and a factor to account for heat 

transfer fluid) to estimate emissions in 

40 CFR 98.91(a)(1) and (2). To estimate 

emissions, facilities would, for each F– 

GHG, apply an input gas emission factor 

of 0.8 and by-product gas formation 

factors of 0.15 for CF4 and 0.05 for C2F6. 

The emission factors we are proposing 

for this optional calculation method are 

included in proposed new Table I–2 of 

subpart I of part 98 and are the same as 

the emission factors we are proposing in 

this rulemaking for gas and process 

combinations for which there is no 

default in Tables I–3, I–4, or I–5, as 

applicable; and the factors are discussed 

further under the updates to emission 

factors in section III.E.1.c of this 

preamble. As discussed in III.E.1.c of 

this preamble, almost all gas and 

process combinations emit CF4 and C2F6

as by-products. Assigning default values 

for these by-products, instead of 

assuming emissions to be equal to gas 

consumption, would result in a more 

accurate emissions estimate, especially 

in cases where the input gas has a 

significantly lower or higher GWP than 

average. An emission factor of 1.0 

would be applied to N2O. Finally, as is 

currently required for the productionbased method, the calculated emissions 

of each F–GHG and N2O would be 

multiplied by the chemical-specific or 

default GWP for that GHG and the 

resulting CO2e emissions would be 

summed across GHGs. The total would 

continue to be multiplied by a factor to 

account for the use of F–HTFs using 

equation I–4. The result would be the 

calculated subpart I contribution toward 

the 25,000 mtCO2e-per-year emissions 

threshold in 40 CFR 98.2(a)(2). 

Facilities that choose to use this 

option for their calculation method 

would be required to track annual gas 

consumption by GHG but would not be 

required to apportion consumption by 

process type for the purposes of 

assessing rule applicability. The EPA is 

proposing a simplified consumptionbased calculation method option for 

semiconductor, MEMS, and LCD 

manufacturing facilities to provide a 

calculation method that could 

appropriately exclude some loweremitting facilities that would otherwise 

be subject to subpart I. Facilities would 

continue to have the option to use the 

manufacturing capacity-based method 

for estimating emissions in 40 CFR 

98.91(a)(1) and (2). Facilities using 

either method would continue to 

calculate total annual GHG emissions, 

including combined emissions from 

stationary fuel combustion units and 

other applicable source categories, for 

comparison to the 25,000 mtCO2e per 

year emission threshold in 40 CFR 

98.2(a)(2). 

Facilities that manufacture PV already 

have a consumption-based method in 

the current rule. However, currently, the 

applicability calculation for PV 

manufacturing includes only GHGs 

‘‘that have listed GWP values in Table 

A–1 to subpart A of this part.’’ Because 

default GWPs are now available for F– 

GHGs that do not have chemicalspecific GWPs in Table A–1, we are 

proposing to delete the limiting phrase 

‘‘that have listed GWP values in Table 

A–1.’’ We are also proposing to revise 


jspears on DSK121TN23PROD with PROPOSALS2
36956 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

53 IPCC. Guidelines for National Greenhouse Gas 

Inventories, Volume 3, Ch. 6 Electronics Industry 

Emissions, 2006. https://www.ipcc-nggip.iges.or.jp/ 

public/2006gl/. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

54Refer to Technical Support Document for 

Process Emissions from Electronics Manufacture 

(e.g., Micro-electro-mechanical Systems, Liquid 

Crystal Display, Photovoltaics, and 

Semiconductors), November 2010, available in the 

docket for this rulemaking, Docket Id. No, EPA– 

HQ–OAR–2019–0424. 

55See Volume 3, Chapter 6. Electronics Industry 

Emissions to the 2019 Refinement to the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories, as cited above in this document. 56Supra note 51. 

equation I–3 to be identical to the new 

equations I–1B and I–2B and to also use 

newly proposed Table I–2. As for 

semiconductor, MEMS, and LCD 

manufacturers, this revision is expected 

to increase the accuracy of the estimated 

emissions for determining applicability. 

We are also proposing to revise the 

emission factors in Table I–1 used for 

estimating emissions for MEMS and 

LCD manufacturing when equation I–1A 

(based on production in substrate area) 

is used to assess the applicability of part 

98. The emission factors currently in 

Table I–1 include emissions factors for 

semiconductor, LCD, and MEMS 

manufacturing. For semiconductor and 

LCD manufacturing, the emissions 

factors that are currently in Table I–1 

are based on the Tier 1 default emission 

factors in Vol. 3, Ch. 6 Electronics 

Industry Emissions in the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories.53

For MEMS manufacturing, there were 

no IPCC Tier 1 factors available at the 

time of the 2010 Final Rule for 

Additional Sources of Fluorinated GHGs 

(75 FR 74774), and the emission factors 

were instead based on the IPCC Tier 2b 

SF6 emission factor for 

semiconductors.54 The 2019 Refinement 

included an update to the IPCC 

Guidelines Tier 1 emission factors using 

newly available data.55 For LCD and 

MEMS manufacturing, the EPA has 

tentatively determined that the new Tier 

1 emission factors in the 2019 

Refinement would better reflect 

industry-wide technological trends and 

are expected to improve the accuracy of 

the emissions estimated for the GHGRP 

using Table I–1. However, for 

semiconductor manufacturing, emission 

rates vary significantly depending on 

the wafer size used for manufacturing, 

and therefore no single set of default 

emission factors accurately estimates 

emissions for all wafer sizes. The Tier 

1 emission factors in the 2019 

Refinement are, overall, lower than 

those in the 2006 IPCC Guidelines 

because they reflect the increasing 

importance of the 300-mm wafer size 

technology, which has lower emission 

rates than the older but still significant 

200-mm (or smaller) wafer size 

technology. (The Tier 1 emission factors 

in the 2019 Refinement were developed 

assuming a 50/50 split between 200-mm 

and 300-mm wafer production.) To 

estimate emissions for manufacturing 

using the 200-mm wafer size, the 2019 

Refinement recommends that the Tier 1 

emission factors in the 2006 IPCC 

Guidelines be used because they more 

accurately reflect emission rates for that 

wafer size than do the Tier 1 emission 

factors in the 2019 Refinement. Use of 

the Tier 1 emission factors in the 2019 

Refinement would underestimate 

emissions from facilities manufacturing 

on wafers sized 200 mm or smaller. In 

addition, our analysis (CBI TSD 

Comparison of Subpart I Emissions to 

New Tier 1 EFs, available in the docket 

for this rulemaking, Docket Id. No. 

EPA–HQ–OAR–2019–0424 56) indicates 

that use of these factors would 

underestimate emissions from a few 

facilities manufacturing on wafers sized 

300 mm. To maintain the simplicity of 

the applicability calculation in equation 

I–1A for semiconductors, the EPA 

prefers to retain a single set of default 

emission factors for semiconductors in 

Table I–1, and to ensure that facilities 

manufacturing on the 200-mm wafer 

size are not improperly excluded from 

coverage by the GHGRP, we are not 

proposing to revise the emission factors 

for semiconductor manufacturing in 

Table I–1. While this could result in 

overestimated emissions for some 

facilities that manufacture on the 300- 

mm wafer size, the EPA notes that such 

facilities would have the option to use 

gas consumption data rather than 

capacity in square meters to assess 

applicability, as discussed above. 

There is no expected impact on the 

number of LCD manufacturing facilities 

reporting to the GHGRP due to the 

proposed update to those emission 

factors, as there are currently no known 

LCD manufacturers in the United States. 

For MEMS manufacturers, the proposed 

update to Table I–1 could possibly 

result in one additional facility 

reporting to the GHGRP (estimated to 

have annual emissions greater than or 

equal to 25,000 mtCO2e). However, due 

to a lack of actual capacity data, it is 

difficult to assess with precision how 

many facilities, if any, would be 

impacted. 

b. Revisions to the Frequency and 

Applicability of the Technology 

Assessment Report 

For the reasons described in section 

II.B.3 of this preamble, we are proposing 

to revise the frequency and applicability 

of the technology assessment report 

requirements in 40 CFR 98.96(y), which 

applies to semiconductor manufacturing 

facilities with GHG emissions from 

subpart I processes greater than 40,000 

mtCO2e per year. (Other proposed 

changes to 40 CFR 98.96(y) are 

discussed in section III.E.1 of this 

preamble.) The purpose of the 

technology assessment report is to 

provide regular review of technology 

changes in the semiconductor 

manufacturing industry and ensure that 

default gas utilization rates, by-product 

formation rates, and DRE values 

accurately reflect changes in the 

industry’s practices, such as the 

introduction of manufacturing on 450- 

mm sized wafers. In the 2012 proposed 

amendments to subpart I (77 FR 63538, 

October 16, 2020), we noted that the 

semiconductor manufacturing industry 

had historically been ‘‘fast-evolving, 

achieving exponentially increasing 

processor speeds and improving 

manufacturing efficiencies through the 

rapid adoption of new manufacturing 

processes’’ (see 77 FR 63565). At that 

time the EPA had identified the 

potential introduction of 450 mm wafer 

technology, as well as other new process 

technologies that could affect emissions. 

Therefore, we considered a three-year 

report appropriate for collecting 

information on changes in the 

semiconductor industry that would 

potentially affect emissions. However, 

following submission and review of the 

first three-year reports, we have 

determined that industrial 

advancements are occurring at a slower 

pace. As such, we are proposing to 

amend 40 CFR 98.96(y) to decrease the 

frequency of submission of the reports 

from every three years to every five 

years. Under the current rule, 

semiconductor manufacturing facilities 

are required to submit their next 

technology assessment report by March 

31st, 2023 (concurrent with their 

RY2022 annual report). This proposed 

revision would affect the due date for 

that technology assessment, moving the 

due date from March 31, 2023, to March 

31, 2025. Our review of the technology 

assessment reports submitted for 

RY2016 and RY2019 did not find 

significant technology changes within 

the industry over the three years the 

reports covered. Based on an assessment 

of the RY2016 and RY2019 reports (CBI 

memorandum, Review of 2017 Subpart 


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57Supra note 51. 

58See U.S. EPA, Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990–2019 (EPA 2021), 

available at: https://www.epa.gov/ghgemissions/ 

inventory-us-greenhouse-gas-emissions-and-sinks1990-2019. 

I Triennial Reports Submitted by the 

Electronics Industry (Transcarbon 

International, 2017, available in the 

docket for this rulemaking, Docket Id. 

No. EPA–HQ–OAR–2019–0424) 57 gas 

emissions and wafer size data that have 

been submitted to e-GGRT in annual 

reports, and information gathered from 

outside sources (summarized in a 

literature review, Memorandum: Review 

of trade and scientific publications to 

identify significant recent changes in 

technologies and gas usage in electronic 

devices manufacturing, prepared by 

Se ́bastien Raoux, Transcarbon 

International, and Brian Palmer, Eastern 

Research Group, Inc. (April 3, 2017), 

available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424), we believe that a 

five-year period would provide updates 

to the EPA more in line with the pace 

of technological change within the 

semiconductor industry. Revising the 

frequency of submission to every five 

years would increase the likelihood that 

reports will include updates in 

technology rather than conclusions that 

technology has not changed. Because we 

have found that changes within the 

industry have been incorporated at a 

slower pace and do not anticipate 

significant changes in technology on a 

three-year frequency, the proposal to 

require submission of these reports on a 

five-year frequency would likely not 

significantly affect the quality of the 

data available annually in the GHGRP. 

Second, we are proposing to revise 

the applicability of 40 CFR 98.96(y). 

Currently, any facility with emissions 

greater than 40,000 mtCO2e in their 

most recently submitted emissions 

report must submit a technology 

assessment report, including facilities 

manufacturing devices only using wafer 

sizes smaller than 200 mm (e.g., 150 

mm). Because the focus of the 

technology assessment report is on 

semiconductor manufacturing using 

200-mm, 300-mm, and potentially 450- 

mm wafers (see 40 CFR 98.96(y)(2)(i)– 

(iii)), we are proposing to restrict the 

reporting requirement in 40 CFR 

98.96(y) to facilities that emitted greater 

than 40,000 mtCO2e and produced 

wafer sizes greater than 150 mm (i.e., 

200 mm or larger) during the period 

covered by the technology assessment 

report. We are also proposing to 

explicitly state that semiconductor 

manufacturing facilities that 

manufacture only 150-mm or smaller 

wafers are not required to prepare and 

submit a technology assessment report. 

The applicability of 40 CFR 98.96(y) is 

currently based on the emissions in a 

facility’s most recently submitted report 

(typically the emissions occurring in the 

second-to-last year covered in the 

technology assessment report, e.g., 

RY2022 emissions for the technology 

reports that would be submitted in 

2023). However, because facilities that 

cease all operations related to subpart I 

are eligible to discontinue reporting 

under 40 CFR 98.2(i)(3), we are also 

proposing to further revise the 

applicability of 40 CR 98.96(y) to clarify 

that a technology assessment report 

need not be submitted by a facility that 

has ceased (and has not resumed) 

semiconductor manufacturing before the 

last reporting year covered by the 

technology assessment report (i.e., no 

manufacturing at the facility for the 

entirety of the year immediately before 

the year during which the technology 

assessment report is due). For example, 

if a facility manufacturing on 300-mm 

wafers exceeded the 40,000 mtCO2e 

threshold in 2023 but ceased operations 

in December of that year and has not 

since then resumed operations, that 

facility would not be required to submit 

a technology assessment report in 

March of 2025. 

F. Subpart N—Glass Production 

For the reasons described in section 

II.A.4 of this preamble, we are 

proposing two revisions to the 

recordkeeping and reporting 

requirements of subpart N of part 98 

(Glass Production) to enhance the 

quality and accuracy of the data 

collected under the GHGRP. Subpart N 

currently requires calculation of CO2

emissions using one of two 

methodologies, either direct 

measurement using CEMS, or a mass 

balance methodology based on mass, 

carbonate content, and fraction of 

calcination for each carbonate-based 

input material. For each option, 

reporters are required to provide the 

annual quantities of glass produced 

from each glass melting furnace, and the 

annual quantities of glass produced 

from all furnaces combined. The annual 

quantities of glass produced have been 

used historically in verification of 

reported emissions under the GHGRP 

for comparison to, and to check for 

temporal consistency with, carbonate 

content data and emissions estimates 

provided by facilities. Facilities also 

maintain records of monthly glass 

production rate for each glass furnace. 

We are proposing to revise the existing 

reporting and recordkeeping 

requirements for both CEMS and nonCEMS reporters to require that facilities 

report and maintain records of annual 

glass production by glass type. 

Specifically, we are proposing to revise 

40 CFR 98.146(a)(2) and (b)(3) to require 

the annual quantity of glass produced in 

tons, by glass type, from each 

continuous glass melting furnace and 

from all furnaces combined, and the 

annual quantity of glass produced in 

tons, by glass type, from each 

continuous glass melting furnace and 

from all furnaces combined. The major 

raw materials (i.e., fluxes and 

stabilizers) that emit process-related 

CO2 emissions in glass production are 

limestone, dolomite, and soda ash, 

though there are variations in 

ingredients and other carbonates may be 

used in smaller quantities. In general, 

the composition profile of raw materials 

is relatively consistent among 

individual glass types (e.g., container, 

flat glass, fiber glass, specialty glass), 

however, some facilities make use of 

recycled glass in their production 

process. Differences in the use of 

recycled material, and other factors, 

lead to differences in emissions from the 

production of different glass types. The 

annual quantities of glass produced by 

type would provide a useful metric for 

understanding variations and 

differences in emissions estimates that 

may not be apparent in the existing 

annual production data collected, 

improve our understanding of industry 

trends, and improve verification for the 

GHGRP. The proposed data elements 

would also provide useful information 

to improve analysis of this sector in the 

U.S. GHG Inventory. As noted in the 

2019 U.S. GHG Inventory report,58 the 

EPA reviews the GHGRP data in the 

development of inventory estimates for 

this sector to help understand the 

completeness of emission estimates and 

for quality control. Including glass 

product type would increase the 

transparency of the data set produced by 

the Inventory. In addition to the 

proposed reporting of these data 

elements, we are proposing harmonizing 

revisions in 40 CFR 98.147(a)(1) and 

(b)(1), to add that records must also be 

kept on the basis of glass type. 

We do not anticipate that the 

proposed data elements would require 

any additional monitoring or data 

collection by reporters, as annual 

production data by glass type is likely 

available in existing company records. 

The proposed changes would therefore 

result in minimal additional burden to 

reporters. We are also proposing related 

confidentiality determinations for the 


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59TFI’s Comments on the Proposed ‘‘2013 

Revisions to the Greenhouse Gas Reporting Rule 

and Proposed Confidentiality Determinations for 

New or Substantially Revised Data Elements,’’ 

Docket Id. No. EPA–HQ–OAR–2012–0934, May 2, 

2013. Also available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

60TFI’s Comments on the Proposed ‘‘2015 

Revisions and Confidentiality Determinations for 

Data Elements under the Greenhouse Gas Reporting 

Rule,’’ Docket Id. No. EPA–HQ–OAR–2015–0526– 

0064, March 30, 2016. Also available in the docket 

for this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

additional data elements, as discussed 

in section VI of this preamble. 

G. Subpart P—Hydrogen Production 

1. Proposed Revisions To Improve the 

Quality of Data Collected for Subpart P 

As discussed in section II.A of this 

preamble, we are proposing several 

amendments to enhance the quality of 

the data collected under subpart P of 

part 98 (Hydrogen Production). 

Subpart P estimates CO2 emissions 

from hydrogen production units using a 

carbon mass balance along with an 

assumption that all carbon is 

transformed to CO2 and is emitted from 

the hydrogen production process. This 

assumption is reasonable for the 

majority of hydrogen production units 

because these facilities produce 

hydrogen using either steam methane 

reforming or partial oxidation, followed 

by a water-gas-shift reaction. The first 

step (steam methane reforming or partial 

oxidation) produces a mixture of carbon 

monoxide (CO) and hydrogen, 

commonly referred to as syngas. The 

water gas shift reaction uses water to 

react with the CO in the syngas to 

produce CO2 and additional hydrogen. 

While the majority of hydrogen 

production units use the water-gas-shift 

reaction, some facilities only produce 

syngas as their product. Some facilities 

may also intentionally produce 

methanol as a product of these 

reactions. In these cases, the assumption 

that 100 percent of the carbon used in 

the process is converted to CO2 and thus 

are direct CO2 emissions from hydrogen 

production units is inaccurate. 

As noted in section III.C of this 

preamble for subpart G (Ammonia 

Manufacturing), TFI has commented 

numerous times regarding its view of 

the lack of a true mass balance for 

subpart G. In several of their comments 

(specifically, TFI’s Comments on the 

Proposed ‘‘2013 Revisions to the 

Greenhouse Gas Reporting Rule and 

Proposed Confidentiality 

Determinations for New or Substantially 

Revised Data Elements,’’ May 2, 2013, 

and Comments on the Proposed ‘‘2015 

Revisions and Confidentiality 

Determinations for Data Elements under 

the Greenhouse Gas Reporting Rule,’’ 

March 30, 2016),59 60 TFI stated that 

subpart P lacked a true mass balance 

because the emissions calculation 

methodology in 40 CFR 98.163 does not 

account for carbon that is bound in 

methanol or other by-products of the 

process and therefore is not emitted as 

CO2. TFI pointed out that subpart P 

requires reporting of methanol that is 

intentionally produced and ‘‘carbon 

other than CO2’’ that is transferred off 

site, but that the emissions calculation 

methodology in 40 CFR 98.163 still 

assumes that 100 percent of the carbon 

is emitted as CO2 because the mass 

balance equations do not subtract out 

the carbon that leaves the facility as 

methanol or another product. 

Syngas is used as a feedstock for 

chemical production, most commonly to 

produce methanol. Carbon transformed 

into methanol or other chemicals are not 

emitted as CO2 unless the syngas is used 

directly as fuel. For fuel combustion 

units other than the hydrogen process 

units, and to which subpart C (General 

Stationary Fuel Combustion Sources) 

applies, the CO2 emissions from syngas 

combustion would be reported under 

subpart C of part 98. In considering TFI 

comments, as noted in the preamble to 

the November 2013 amendments (78 FR 

71935, November 29, 2013), we 

considered both the emissions from the 

production processes and consistency 

with the reporting requirements for 

other subparts. We note that subpart X 

(Petrochemical Production) uses a more 

direct mass balance approach in that 

carbon contained in produced products 

(e.g., ethylene) is subtracted from the 

carbon contained in feedstocks to 

calculate CO2 emissions. The EPA has 

tentatively concluded that requiring 

reporters subject to subpart P to report 

net CO2 process emissions after 

subtracting out carbon contained in 

other products would provide a more 

accurate estimate of the direct GHG 

emissions from these processes and 

would provide consistency in our 

approach across the GHGRP. Therefore, 

the EPA is proposing to amend subpart 

P to allow the subtraction of carbon 

contained in products other than CO2

(excluding methanol) and the carbon 

contained in methanol from the carbon 

mass balance used to estimate CO2

emissions. The proposed revisions 

would add new paragraph 40 CFR 

98.163(d) to allow facilities to adjust the 

calculated emissions from fuel and 

feedstock consumption to subtract the 

mass of both non-CO2 carbon (excluding 

methanol) and carbon contained in the 

intentionally produced methanol in 

order to calculate net CO2 process 

emissions. We are also proposing 

harmonizing revisions to the 

introductory paragraph of 40 CFR 

98.163 and 40 CFR 98.163(b). 

In conjunction with adding the new 

paragraph to 40 CFR 98.163(d), we are 

proposing a clarifying revision to the 

reporting requirements at 40 CFR 

98.166(b)(1) to specify that the annual 

CO2 emissions may be determined in 

accordance with either 40 CFR 

98.163(b), the existing equations, or 40 

CFR 98.163(d), the revision requiring 

the calculation of net CO2 emissions 

using equation P–4. We are proposing to 

revise 40 CFR 98.166(d) to require 

reporting the mass of non-CO2 carbon 

(excluding methanol) collected and 

transferred off-site for each process unit 

rather than for all process units 

combined, as currently reported. 

Reporters are already required to 

account for and report under 40 CFR 

98.166(d) the mass of non-CO2 carbon 

(excluding methanol) collected and 

transferred off-site for all process units 

combined and under 40 CFR 98.166(e) 

the mass of methanol produced for each 

process unit. This proposed revision 

would cause a slight increase in 

reporting burden, but the additional 

level of reporting is necessary to 

implement the requested change in the 

calculation method and facilitate report 

verification. The proposed revision 

would provide the same breadth of 

information that was previously 

reported to inform future policy 

decisions. Additionally, this data 

element may be determined using 

company records, which also should 

minimize the increased burden. We are 

proposing related confidentiality 

determinations for the additional data 

elements, as discussed in section VI of 

this preamble. 

As a result of the new equation P–4, 

the EPA is proposing to add two new 

monthly recordkeeping elements as part 

of the verification software records 

required in 40 CFR 98.167(e): (1) 

monthly mass of carbon other than CO2

or methanol collected and transferred 

off site; and (2) monthly mass of 

methanol intentionally produced as a 

desired product. This proposed change 

is not expected to result in a significant 

increase in burden because both 

elements are already being reported on 

an annual basis. For reporters that do 

not produce carbon other than CO2

(excluding methanol) or methanol, the 

requirements for recordkeeping would 

remain unchanged. We are also 

clarifying that retention of the file 

required in 40 CFR 98.167(e) satisfies 


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the recordkeeping requirements for each 

hydrogen production unit. 

2. Proposed Revisions To Streamline 

and Improve Implementation for 

Subpart P 

We are proposing several revisions to 

subpart P to streamline the requirements 

of this subpart and improve flexibility 

for reporters. First, we are proposing 

several revisions to address 

unconventional feedstocks being used 

for hydrogen production. For example, 

in RY2017, a new facility started 

reporting under subpart P that produced 

hydrogen via brine electrolysis. 

Additionally, we understand facilities 

are considering using anhydrous 

ammonia as a feedstock for hydrogen 

production. The test methods included 

in 40 CFR 98.164(b)(5) are generally not 

applicable for these feedstocks. 

Moreover, the reduced, annual 

measurement frequency allowances in 

40 CFR 98.164(b)(2) and (3) are specific 

to ‘‘hydrocarbon fuels and feedstocks 

having consistent composition’’ 

[emphasis added]. 

To address the recent use of 

unconventional non-hydrocarbon 

feedstocks, and for the reasons 

described in section II.B.2 of this 

preamble, we are proposing to add an 

allowance in a new paragraph 40 CFR 

98.164(b)(5)(xix) to use alternative 

methods if the methods currently in 40 

CFR 98.164(b)(5) are not appropriate 

because the relevant compounds cannot 

be detected, the quality control 

requirements are not technically 

feasible, or use of the method would be 

unsafe. Similar provisions have been 

provided in other GHGRP subparts, 

such as subpart X. This proposed 

revision will ensure that subpart P will 

not mandate the use of inappropriate or 

unsafe methods for these 

unconventional feedstocks. 

Additionally, we are proposing 

revisions to 40 CFR 98.164(b)(2) and (3) 

to allow the use of product specification 

information annually for nonhydrocarbon gaseous fuels and 

feedstocks that have carbon content less 

than or equal to 20 parts per million by 

weight (i.e., 0.00002 kg carbon per kg of 

gaseous fuel or feedstock) rather than at 

least weekly sampling and analysis. 

Similarly, we are proposing revisions to 

40 CFR 98.164(b)(3) to allow the use of 

product specification information 

annually for non-hydrocarbon liquid 

fuels and feedstocks that have a carbon 

content of less than or equal to 0.00006 

kg carbon per gallon of liquid fuel or 

feedstock rather than monthly sampling 

and analysis. The value of 0.0006 kg/ 

gallon was derived using 20 parts per 

million by weight and assuming the 

liquid that has a specific gravity of 0.8 

(i.e., a density of approximately 3.0 kg/ 

gal). The current unconventional nonhydrocarbon fuels and feedstocks 

utilized in hydrogen production have 

very limited GHG emission potential 

and are currently an insignificant 

contribution to the GHG emissions from 

hydrogen production. Therefore, we 

consider it reasonable to provide a 

simple alternative of allowing use of 

product specification information on an 

annual basis for determining carbon 

content for these unconventional, nonhydrocarbon fuels and feedstocks. 

We are also proposing revisions to 40 

CFR 98.164(b)(5) to clarify that the 

methods in 40 CFR 98.164(b)(5) must be 

used for determining carbon content 

except for the newly proposed 

provisions for gaseous and liquid fuels 

and feedstocks that have a low carbon 

content as provided in paragraphs 40 

CFR 98.164(b)(2) and (3). Additionally, 

we are proposing to revise paragraphs 

40 CFR 98.164(b)(2) through (4) to 

specifically state that the carbon content 

must be determined ‘‘. . . using the 

applicable methods in paragraph (b)(5) 

of this section.’’ This proposed revision 

does not alter the existing requirements 

for fuels and feedstocks, it simply 

clarifies the linkage between the 

requirements in paragraphs 40 CFR 

98.164(b)(2) through (4) and (5) of the 

current rule. 

These proposed revisions to address 

unconventional hydrogen production 

feedstocks would increase flexibility for 

reporters and clarify requirements to 

reduce the number of reporters 

performing monthly sampling and 

analysis using potentially inappropriate 

methods. We expect that the proposed 

changes would allow reporters using 

unconventional non-hydrocarbon fuels 

and feedstocks to use the proposed 

product specifications provisions and 

reduce the need for sampling and 

analysis. Even if the reporter cannot use 

the product specifications provisions, 

the proposed revision to allow the use 

of modified or alternative methods 

would likely reduce the analytical 

burden of trying to use hydrocarbonfocused methods for a non-hydrocarbon 

stream. While the proposed revisions 

would provide significant relief for 

those reporters using unconventional 

non-hydrocarbon fuels or feedstocks, 

the proposed change is expected to only 

affect a small number of reporters due 

to the limited number of reporters that 

currently use these types of feedstocks. 

In providing these alternatives, we 

also evaluated whether amendments to 

the recordkeeping and reporting 

requirements were necessary. There are 

no direct reporting requirements for the 

analytical method used to determine 

carbon content. The recordkeeping 

requirements are included in 40 CFR 

98.167(b), which requires retention of 

‘‘. . . records of all analyses and 

calculations conducted as listed in 40 

CFR 98.166(b), (c), and (d).’’ In 

reviewing these requirements, we noted 

that these recordkeeping requirements 

were not revised when the EPA added 

reporting requirements at 40 CFR 

98.166(e) (79 FR 63787, Oct. 24, 2014). 

Therefore, we are proposing to revise 

the recordkeeping requirements at 40 

CFR 98.167(b) to refer to paragraphs (b) 

through (e) of 40 CFR 98.166. We note 

that, for facilities using the proposed 

alternatives at 40 CFR 98.164(b)(2), (3) 

or (5)(xix), these requirements include 

retention of product specification 

sheets, records of modifications to the 

methods listed in 40 CFR 98.164(b)(5)(i) 

through (xviii) that are used, and 

records of the alternative methods used, 

as applicable. 

H. Subpart Q—Iron and Steel 

Production 

1. Proposed Revisions To Improve the 

Quality of Data Collected for Subpart Q 

For the reasons described in section 

II.A.4 of this preamble, we are 

proposing revisions to the reporting 

requirements for subpart Q of part 98 

(Iron and Steel Production) to enhance 

the quality and accuracy of the data 

collected. Subpart Q currently requires 

calculation of CO2 emissions using one 

of three methodologies: direct 

measurement using CEMS, carbon mass 

balance methodologies, or site-specific 

emission factors. Subpart Q requires 

that the CO2 emissions be calculated 

and reported for the following types of 

units: taconite indurating furnace, basic 

oxygen furnace, non-recovery coke oven 

battery, sinter process, EAF, 

decarburization vessel, and direct 

reduction furnace. We are proposing to 

revise the existing reporting 

requirements at 40 CFR 98.176(g) for all 

unit types and all calculation methods 

to require that facilities report the type 

of unit, the annual production capacity, 

and the annual operating hours for each 

unit. The capacity of the unit as well as 

the level of operation have a significant 

influence on the emissions of that unit. 

Therefore, the annual production 

capacity in combination with annual 

operating hours would provide useful 

information for understanding 

variations in annual emissions and 

would provide useful information to 

verify reported data. We often contact 

facilities seeking to understand yearly 

variations in the emissions of a unit, 

and facilities explain that the variation 


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was due to the unit not operating for a 

particular time period. If data on the 

capacity of the unit and the operating 

hours are included in the annual report, 

it could explain the variation and 

eliminate the need for correspondence 

with facilities. In addition, this data 

would provide useful information to 

understand trends across the sector and 

support analysis of these sources. 

In general, we do not anticipate that 

the proposed data elements would 

require any additional monitoring or 

data collection by reporters. For 

facilities using the carbon mass balance 

method, this data is already included in 

the record keeping requirements 

described at 40 CFR 98.177(c) and (d). 

Although the record keeping 

requirement at 40 CFR 98.177(d) does 

not specify whether the data would be 

retained at the facility or unit level, we 

do not anticipate that reporting data at 

the unit level would present additional 

burden. For facilities using the CEMS 

method or the site-specific emission 

factor calculation method, we anticipate 

that this data would be readily available 

in company records. However, we seek 

comment on both these assumptions. 

We are proposing related confidentiality 

determinations for the additional data 

elements, as discussed in section VI of 

this preamble. 

For the reasons described in section 

II.A.5 of this preamble, we are 

proposing to correct equation Q–5 in 40 

CFR 98.173(b)(1)(v). An error appears to 

have been introduced in equation Q–5 

in revisions to the equation in a final 

rule published in 2016 (81 FR 89188, 

December 9, 2016). Specifically, the 

final rule inadvertently published the 

equation such that it appeared that the 

total CO2 emissions from EAFs are 

determined as a fraction of, rather than 

the total of, carbon mass emissions from 

inputs to the furnace. The proposed 

revisions would correct the equation to 

remove the unnecessary fraction symbol 

and would not add additional burden 

for the calculation or reporting 

requirements for subpart Q. 

2. Proposed Revisions To Streamline 

and Improve Implementation for 

Subpart Q 

For the reasons described in section 

II.B.2 of this preamble, we are proposing 

two revisions to subpart Q to streamline 

monitoring. First, we are proposing to 

revise 40 CFR 98.174(b)(2) to provide a 

new option for facilities to determine 

the carbon content of process inputs and 

outputs. Reporters are currently allowed 

to determine carbon content either 

through direct sampling using the 

methods provided in 40 CFR 

98.174(b)(2) or from similar analyses 

provided by a supplier. We are 

proposing to allow reporters an 

additional third option to use analyses 

provided by material recyclers that 

manage process outputs for sale or use 

by other industries. Several of the 

process output materials used in iron 

and steel production are typically sent 

to recycling facilities (e.g., secondary 

zinc recycling facilities), which process 

the material for supply to another entity. 

Such material recyclers conduct testing 

on their inputs and products to provide 

to entities using the materials 

downstream, and therefore perform 

carbon content analyses using similar 

test methods and procedures as 

suppliers. In the 2009 Final Rule, we 

determined that the use of carbon 

content analyses from a material 

supplier was appropriate because the 

carbon content does not vary widely at 

a given facility for the significant 

process inputs and outputs that contain 

carbon, and because the EPA continued 

to account for variations in emissions 

due to changes in production rate, 

which are more likely to be a significant 

source of variability (i.e., the quantity of 

carbon-containing materials that are 

inputs and outputs to the process more 

directly influence emissions). For these 

same reasons, we anticipate that 

analyses received from a material 

recycling entity would be a reliable 

source of carbon content. The proposed 

change would add flexibility for 

reporters by allowing an additional 

option for obtaining measurements, in 

lieu of direct sampling. We are 

proposing a minor harmonizing change 

to 40 CFR 98.176(e)(2) to require 

reporters to indicate if the carbon 

content was determined from 

information supplied by a material 

recycler. 

We are also proposing to revise 40 

CFR 98.174(b)(2) to incorporate a new 

test method for carbon content analysis 

of low-alloy steel. The EPA has become 

aware that an additional method is 

available for analysis of carbon content, 

specifically, ASTM E415–17, Standard 

Test Method for Analysis of Carbon and 

Low-Alloy Steel by Spark Atomic 

Emission Spectrometry (2017). We have 

reviewed the method, which is targeted 

to this sector, and have tentatively 

concluded it is a valid method for the 

purposes of subpart Q monitoring and 

reporting. The EPA allows for the use of 

standard methods based on atomic 

emission spectrometry in other sections 

of the rule, including under 40 CFR 

98.144(b) where it can be used to 

determine the composition of coal, coke, 

and solid residues from combustion 

processes by glass production facilities. 

Therefore, we are proposing to 

incorporate the method by reference in 

40 CR 98.7 and cross-reference that 

incorporation in 40 CFR 98.174(b)(2) for 

use for steel, as applicable. The 

proposed test method would be an 

alternative method and would provide 

additional flexibility for reporters. We 

are also proposing a harmonizing 

change to the reporting requirements of 

40 CFR 98.176(e)(2), to clarify that the 

carbon content analysis methods 

available to report are those methods 

listed in 40 CFR 98.174(b)(2). 

I. Subpart S—Lime Manufacturing 

For the reasons discussed in this 

section and section II.A of this 

preamble, we are proposing several 

revisions to subpart S of part 98 (Lime 

Manufacturing) to improve the quality 

of the data collected from this subpart. 

First, for the reasons described in this 

section and in section II.A.2 of this 

preamble, we are proposing to amend 

subpart S to improve the methodology 

for calculation of annual CO2 process 

emissions from lime production. The 

proposed revisions would account for 

CO2 that is captured from lime kilns and 

used on-site. Under subpart S, reporters 

currently calculate CO2 emissions by 

either operating and maintaining a 

CEMS as specified in 40 CFR 98.193(a) 

or (b)(1), or by using the mass balance 

methodology under 40 CFR 98.193(b)(2). 

All lime kilns that are subject to 40 CFR 

98.193(b) must calculate and report 

process and combustion CO2 emissions 

by using the procedures in either 40 

CFR 98.193(b)(1), for estimation of 

combined process and combustion 

emissions from all lime kilns, or 40 CFR 

98.193(b)(2), for estimation of process 

and combustion CO2 emissions from all 

lime kilns separately. For those lime 

kilns that use 40 CFR 98.193(b)(2), 

calculation of annual CO2 process 

emissions from all lime kilns is 

estimated through summing the 

following three values (per 40 CFR 

98.193(b)(2)(iv)): (1) the product of a 

monthly site-specific emission factor 

and weight or mass for each type of lime 

produced, (2) the product of a monthly 

site-specific emission factor and each 

type of calcined byproduct or waste that 

is sold, and (3) the annual CO2

emissions from each type of calcined 

byproduct or waste that is not sold. 

There is currently no allowance for 

subtraction of CO2 that may be captured 

and used in another process on-site 

(e.g., for use in a purification process or 

the manufacture of another product 

such as refined beet sugars, precipitated 

calcium carbonate, etc.). 

In response to the 2009 Proposed 

Rule, one subpart S reporter, Specialty 


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61Specialty Minerals Inc.’s Comments on the 

Proposed 2009 Greenhouse Gas Reporting Rule, 

Docket Id. No. EPA–HQ–OAR–2008–0508–0907, 

June 4, 2009. Also available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

62Subpart S reporters who use the mass balance 

methodology under 40 CFR 98.193(b)(2) currently 

estimate CO2 emissions using monthly chemical 

composition data as inputs to calculate emissions 

factors for the lime produced, calcined byproducts 

and wastes sold, and calcined byproducts and 

wastes not sold. These data inputs are not collected 

by the EPA but are only entered into the EPA’s 

Inputs Verification Tool, which conducts 

verification checks at the time of report submission 

but does not retain the data entered. 

Minerals Inc., submitted a comment that 

stated that subpart S does not include a 

‘‘deduction for the carbon dioxide that 

is taken up as a raw material’’ for use 

in another product, resulting in ‘‘an 

overstatement of total carbon dioxide 

emissions’’ from lime manufacturing.61

In section III.C of this preamble, we 

describe similar comments received 

from TFI requesting changes that would 

allow sources to subtract from direct 

facility emissions CO2 that is being used 

in the manufacturing of other products 

on-site. 

Following review of these comments, 

the EPA has tentatively concluded that 

allowing reporters subject to subpart S 

to report net CO2 process emissions after 

subtracting out CO2 captured and used 

in other on-site processes would 

provide a more accurate estimate of the 

direct GHG emissions from the lime 

manufacturing process and would 

provide consistency in our approach 

across the GHGRP. Therefore, we are 

proposing to modify equation S–4 to 

subtract the CO2 that is captured and 

used in on-site processes, with 

corresponding proposed revisions to the 

recordkeeping requirements in 40 CFR 

98.197(c) (to record the monthly amount 

of CO2 from the lime manufacturing 

process that is captured for use in all 

on-site processes). We are also 

proposing minor amendments to the 

reporting elements in 40 CFR 

98.196(b)(17) to clarify that we only 

intend to collect data on CO2 that is 

captured and used on-site (i.e., reporters 

do not need to account for CO2 that was 

not captured but was used on-site), and 

to clarify that reporters must account for 

CO2 usage from all on-site processes, 

including for manufacture of other 

products, in the total annual amount of 

CO2 captured. The proposed changes 

would also correct some instances 

where reporters have provided values of 

CO2 used on-site that exceed facility 

emissions, where they have 

inadvertently included CO2 that was not 

captured on-site (e.g., CO2 purchased for 

water treatment), which incorrectly 

implied that the facility’s emissions 

were net negative. The proposed 

amendments would not change the 

reporting of emissions from 

manufacture of lime products, calcined 

lime by-products, or waste; this 

information would continue to be 

collected. As such, the proposed 

amendments would provide the same 

breadth of information that was 

previously reported to inform future 

policy decisions. 

Second, for the reasons described in 

section II.A.4 of this preamble, we are 

proposing to add reporting requirements 

for reporters using the CEMS 

methodology in order to improve our 

understanding of source category 

emissions and our ability to verify 

reported data. Subpart S reporters who 

use CEMS collect CO2 emissions data 

through direct measurement, and no 

data on the chemical composition of the 

products, byproducts, or wastes at 

CEMS facilities are collected through 

the GHGRP.62 As such, there is 

currently limited data available to the 

EPA to evaluate process emissions for 

reporters using CEMS. As we noted for 

cement production facilities in section 

III.D of this preamble, CEMS facility 

emissions are different from non-CEMS 

emissions because combustion and 

process emissions are typically vented 

through the same stack, causing process 

and combustion emissions to be mixed 

and indifferentiable. In order to be able 

to differentiate process emissions, we 

are proposing to collect other data 

elements from CEMS reporters that are 

not currently reported, including annual 

average results of the chemical 

composition analysis of lime products, 

byproducts, or wastes. Collecting 

average chemical composition data for 

CEMS facilities will provide the EPA 

the ability to develop a process emission 

estimation methodology for CEMS 

reporters, which can be used to verify 

the accuracy of the reported CEMS 

emission data. The EPA is proposing to 

add data elements under 40 CFR 

98.196(a) to collect annual averages of 

the chemical composition input data on 

a facility-basis. The proposed data 

elements include the annual arithmetic 

average calcium oxide content (metric 

tons CaO/metric tons lime) and 

magnesium oxide content (metric tons 

MgO/metric tons lime) for each type of 

lime produced, for each type of calcined 

lime byproduct and waste sold, and for 

each type of calcined lime byproduct 

and waste not sold. The proposed data 

elements would rely on an arithmetic 

average of the measurements rather than 

requiring reporters to weight by 

quantities produced in each month. In 

addition to improving verification and 

data quality for the GHGRP, the 

proposed data elements will also 

improve the U.S. GHG Inventory, which 

could use the proposed data elements to 

disaggregate process and combustion 

emissions that are reported by facilities 

using CEMS. 

Similarly, in order to improve 

verification, we are proposing to collect 

additional data elements for reporters 

using the mass balance methodology 

(i.e., reporters that comply using the 

requirements at 40 CFR 98.193(b)(2)). 

These proposed amendments would 

allow the EPA to build verification 

checks for the actual inputs entered 

(e.g., MgO content). We currently rely 

on verification checks within the IVT to 

check the accuracy of inputs and 

reported emissions from non-CEMS 

reporters, however, these checks are of 

limited usefulness since we lack the 

information to develop specific 

anticipated ranges or references for the 

entered data. Reporters using the mass 

balance methodology are currently 

required to report the annual average 

results of chemical composition analysis 

of each type of lime product produced 

and calcined byproduct or waste sold, 

but do not supply data for byproducts 

or wastes not sold. The EPA is 

proposing to add data elements under 

40 CFR 98.196(b) to collect the annual 

average results of the chemical 

composition analysis of all lime 

byproducts or wastes not sold (e.g., a 

single facility average calcium oxide 

content calculated from the calcium 

oxide content of all lime byproduct 

types at the facility), and the annual 

quantity of all lime byproducts or 

wastes not sold (e.g., a single facility 

total calculated as the sum of all 

quantities, in tons, of all lime 

byproducts at the facility not sold 

during the year). Because the proposed 

data elements rely on annual averages of 

the chemical composition 

measurements and an annual quantity 

of all lime byproducts or wastes at the 

facility, they are distinct from the data 

entered into the EPA’s IVT. These 

proposed data elements would inform 

and improve the EPA’s existing 

reference checks and allow the EPA to 

build additional checks for the data that 

are currently verified through IVT. The 

proposed amendments would improve 

the verification of entered data and 

confirm the veracity of reported 

emissions. 

We do not anticipate that the 

proposed data elements would require 

any additional monitoring or data 

collection by reporters, as these data are 

likely already available in existing 

company records. However, we are 

requesting comment on whether any of 


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63 40 CFR part 62 contains a subpart for each of 

the 50 states, District of Columbia, American 

Samoa, Puerto Rico, Virgin Islands, and Northern 

Mariana Islands. 

64When the total emissions from all leaking 

sources of the same type are divided by the total 

count of that source type, then the resultant factor 

is referred to as a population emission factor. When 

the total emissions from all leaking sources of the 

same type are divided by the total count of leaking 

sources for that source type, then the resultant 

factor is referred to as a leaker emission factor. 

the above listed data elements would 

not be readily available to reporters. 

Reporters using the mass balance 

methodology are expected to have very 

minimal changes to reporting, as the 

chemical composition averages and 

quantities we are proposing can be 

calculated from the inputs that are 

currently entered into IVT. Finally, we 

are proposing related confidentiality 

determinations for the additional data 

elements, as discussed in section VI of 

this preamble. 

J. Subpart W—Petroleum and Natural 

Gas Systems 

We are proposing several revisions to 

subpart W (Petroleum and Natural Gas 

Systems). Section III.J.1 of this preamble 

presents proposed amendments that 

would improve the quality of data 

collected, including new requirements 

for reporting of additional emission 

sources, updated emission factors, new 

and revised reporting requirements, and 

clarification of reporting requirements 

that reporters have indicated are 

unclear, as described in section II.A of 

this preamble. We are also proposing 

revisions described in section III.J.2 of 

this preamble that would streamline and 

improve implementation, including 

removing redundant or unnecessary 

reporting requirements, and providing 

additional flexibility in the calculation 

methods and monitoring requirements 

for some emission sources, as described 

in section II.B of this preamble. We are 

proposing the miscellaneous technical 

corrections and clarifications described 

in section III.J.3 of this preamble. 

Finally, section III.J.4 of this preamble 

describes the provisions for which we 

propose subpart W reporters would be 

able to use best available monitoring 

methods (BAMM) for RY2023. We are 

also proposing related confidentiality 

determinations for new or revised data 

elements that result from these 

proposed amendments, as discussed in 

section VI of this preamble. 

In addition, on November 15, 2021 

(86 FR 63110), the EPA proposed under 

CAA section 111(b) NSPS for new, 

reconstructed, and modified oil and 

natural gas sources, i.e., sources for 

which owners or operators commence 

construction, modification, or 

reconstruction after November 15, 2021 

(40 CFR part 60, subpart OOOOb) 

(hereafter referred to as ‘‘NSPS 

OOOOb’’), as well as emissions 

guidelines under CAA section 111(d) for 

existing oil and natural gas sources, i.e., 

sources for which owners or operators 

commence construction, modification, 

or reconstruction on or before November 

15, 2021 (40 CFR part 60, subpart 

OOOOc) (hereafter referred to as ‘‘EG 

OOOOc’’) (the sources affected by these 

two proposed subparts are collectively 

referred to in this preamble as ‘‘affected 

sources’’). While the standards in NSPS 

OOOOb would directly apply to new, 

reconstructed, and modified sources 

when finalized, the final EG OOOOc 

would not impose binding requirements 

directly on sources; rather it would 

contain guidelines, including 

presumptive standards, for states to 

follow in developing, submitting, and 

implementing plans to establish 

standards of performance to limit GHGs 

(in the form of methane limitations) 

from existing oil and gas sources within 

their own states. If a state does not 

submit a plan to the EPA for approval 

in response to the final emission 

guidelines, or if the EPA disapproves a 

state’s plan, then the EPA must establish 

a Federal plan that would apply to 

existing sources within that state that 

are not covered by a state plan. In 

addition, a Federal plan could apply to 

facilities located on tribal land that do 

not request approval to develop a tribal 

implementation plan similar to a state 

plan. Once the Administrator approves 

a state plan under CAA section 111(d), 

the plan is codified in 40 CFR part 62 

(Approval and Promulgation of State 

Plans for Designated Facilities and 

Pollutants) within the relevant subpart 

for that state.63 40 CFR part 62 also 

includes all Federal plans promulgated 

pursuant to CAA section 111(d). 

Therefore, rather than referencing the 

presumptive standards in EG OOOOc, 

which would not directly apply to 

sources, the proposed amendments to 

subpart W reference 40 CFR part 62. 

Similar to the 2016 amendments to 

align subpart W with certain 

requirements in 40 CFR part 60, subpart 

OOOOa (hereafter referred to as ‘‘NSPS 

OOOOa’’) (81 FR 86500, November 30, 

2016), we are proposing revisions to 

certain requirements in subpart W 

relative to the requirements proposed 

for NSPS OOOOb and the presumptive 

standards proposed in the EG OOOOc 

(which would inform the standards to 

be developed and codified under 40 

CFR part 62). Specifically, we are 

proposing amendments to the subpart W 

calculation methodologies for natural 

gas pneumatic devices and equipment 

leak surveys related to the proposed 

NSPS OOOOb and presumptive 

standards in EG OOOOc, and we are 

proposing new reporting requirements 

for ‘‘other large release events’’ as 

defined in subpart W that would 

reference the NSPS OOOOb and 

approved state plans or applicable 

Federal plan in 40 CFR part 62. These 

proposed amendments are described in 

sections III.J.1.a, k, and m, respectively. 

These proposed amendments, if 

finalized, would not apply to individual 

reporters unless and until their emission 

sources are required to comply with 

either the final NSPS OOOOb or an 

approved state plan or applicable 

Federal plan in 40 CFR part 62. In the 

meantime, reporters would comply with 

the applicable provisions of subpart W 

for sources not subject to NSPS OOOOb 

or 40 CFR part 62. 

1. Proposed Revisions To Improve the 

Quality of Data Collected for Subpart W 

As further described in section II.A of 

this preamble, the EPA is proposing 

amendments that would ensure that 

accurate data are being collected under 

the rule, improve the accuracy of 

emissions reported under part 98, and 

enhance the overall quality of the data 

collected under the GHGRP. Consistent 

with section II.A.1 of this preamble, we 

are proposing to incorporate recent data 

to update selected subpart W emission 

factors. Where emission factors are 

currently provided in subpart W for 

certain emission source types, those 

emission factors were based on the best 

available public data at the time that 

subpart W was promulgated. In the 

years since promulgation of subpart W, 

additional data have been collected for 

some source types as part of emissions 

studies, and the EPA has reviewed and 

evaluated the data in these studies. 

Based on those evaluations, the EPA is 

proposing to update selected subpart W 

population emission factors 64 for 

natural gas pneumatic device vents 

across a variety of industry segments 

and equipment leaks from the Onshore 

Petroleum and Natural Gas Production, 

Onshore Petroleum and Natural Gas 

Gathering and Boosting, and Natural 

Gas Distribution industry segments. The 

EPA is also proposing revisions to the 

leaker emission factors for all industry 

segments conducting equipment leak 

surveys to account for differences in the 

leak detection methodologies. 

Consistent with section II.A.2 of this 

preamble, the EPA is proposing 

amendments to improve calculation 

methodologies for emissions from 

natural gas pneumatic pumps, 


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65The development of the current emission 

factors for natural gas pneumatic devices is 

described in Greenhouse Gas Emissions Reporting 

from the Petroleum And Natural Gas Industry: 

Background Technical Support Document, U.S. 

EPA, November 2010, (Docket Id. No. EPA–HQ– 

OAR–2009–0923–3610), also available in the docket 

for this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

66U.S. EPA. Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: Potential Revisions to 

Pneumatic Controller Emissions Estimate 

(Production Segment). April 2015. Available at 

https://www.epa.gov/sites/production/files/2015- 

12/documents/ng-petro-inv-improvementpneumatic-controllers-4-10-2015.pdf. 

centrifugal compressors, reciprocating 

compressors, equipment leak surveys, 

combustion units, and sources that use 

the acoustic leak detection method for 

leak detection. Consistent with section 

II.A.3 of this preamble, we are 

proposing to add calculation and 

reporting requirements for ‘‘other large 

release events,’’ which are emission 

events that are not sufficiently 

accounted for using the current subpart 

W methodologies, and emissions from 

uncombusted methane from compressor 

engines. We are also proposing to 

require facilities in the Onshore Natural 

Gas Processing industry segment to 

begin calculating and reporting 

emissions from natural gas pneumatic 

devices and proposing to require 

facilities in the LNG Import/Export 

industry segment to begin calculating 

and reporting emissions from acid gas 

removal vents. Consistent with section 

II.A.4 of this preamble, we are 

proposing to add or revise reporting 

requirements to better understand and 

characterize the emissions from acid gas 

removal units, glycol dehydrator vents, 

liquids unloadings, atmospheric storage 

tanks, associated gas flaring, flare stacks, 

and equipment leaks, as well as to better 

characterize facilities in the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting industry segment. Finally, 

consistent with section II.A.5 of this 

preamble, we are proposing to clarify 

calculation and reporting requirements 

for natural gas pneumatic devices, 

natural gas driven pneumatic pumps, 

blowdown vent stacks, atmospheric 

storage tanks (including requirements 

for open thief hatches), associated gas 

venting and flaring, centrifugal and 

reciprocating compressors, combustion 

devices, and facilities in the Onshore 

Natural Gas Transmission Pipeline 

industry segment, in part to address 

questions asked by reporters to the 

GHGRP Help Desk and in verification 

correspondence via e-GGRT. 

a. Natural Gas Pneumatic Device Vents 

Revisions to emission factors. Subpart 

W requires calculation of GHG 

emissions from natural gas pneumatic 

device venting using default population 

emission factors multiplied by the 

number of devices and the average time 

those devices are ‘‘in-service’’ (i.e., 

supplied with natural gas). Subpart W 

provides two sets of pneumatic device 

emission factors, one for devices in the 

Onshore Petroleum and Natural Gas 

Production and Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segments and one for the 

Onshore Natural Gas Transmission 

Compression and Underground Natural 

Gas Storage industry segments. Each set 

of emission factors consists of emission 

factors for three different types of 

natural gas pneumatic devices: 

continuous low bleed devices, 

continuous high bleed devices, and 

intermittent bleed devices.65

The EPA has become aware of several 

studies on emissions from natural gas 

pneumatic device vents since subpart W 

was first promulgated. For example, in 

April 2015, the EPA reviewed three 

recently published studies on emissions 

from pneumatic devices (also referred to 

as ‘‘pneumatic controllers’’ within the 

studies as well as in NSPS OOOOa, 

NSPS OOOOb, and EG OOOOc) at 

onshore production facilities and 

evaluated those studies for use in the 

U.S. GHG Inventory.66 As part of this 

proposed rulemaking, we have reviewed 

these and other available studies to 

evaluate the potential for revisions to 

the natural gas pneumatic device 

emission factors in subpart W. For more 

information regarding this review, see 

the document Greenhouse Gas 

Reporting Rule: Technical Support for 

Revisions and Confidentiality 

Determinations for Data Elements 

Under the Greenhouse Gas Reporting 

Rule; Proposed Rule—Petroleum and 

Natural Gas Systems, (hereafter referred 

to as ‘‘subpart W TSD’’), available in the 

docket for this rulemaking, Docket Id. 

No. EPA–HQ–OAR–2019–0424. 

As part of our review, we found there 

are significantly more data available 

now by which to characterize 

pneumatic device emissions. Therefore, 

consistent with section II.A.1 of this 

preamble, we are proposing to amend 

the emission factors for the Onshore 

Petroleum and Natural Gas Production, 

Onshore Petroleum and Natural Gas 

Gathering and Boosting, Onshore 

Natural Gas Transmission Compression, 

and Underground Natural Gas Storage 

industry segments. We are also 

proposing to add pneumatic device 

venting as an emission source for the 

Onshore Natural Gas Processing 

industry segment using the same 

emission factors we are proposing for 

the Onshore Natural Gas Transmission 

Compression and Underground Natural 

Gas Storage industry segments, 

consistent with section II.A.3 of this 

preamble. 

Intermittent bleed pneumatic devices 

subject to surveys. As part of our review 

to characterize pneumatic device 

emissions, we found a significant 

difference in the emissions from 

intermittent bleed pneumatic devices 

that appeared to be functioning as 

intended (short, small releases during 

device actuation) and those that 

appeared to be malfunctioning 

(continuously emitting or exhibiting 

large or prolonged releases upon 

actuation). For natural gas intermittent 

bleed pneumatic devices, it is possible 

to identify malfunctioning devices 

through routine monitoring using 

optical gas imaging (OGI) or other 

technologies. As noted in the 

introduction to section III.J of this 

preamble, the EPA recently proposed 

NSPS OOOOb and EG OOOOc for oil 

and natural gas sources. Under the 

proposed standards in NSPS OOOOb 

and the proposed presumptive 

standards in EG OOOOc (which would 

inform the state plans or, if necessary, 

the Federal plan in 40 CFR part 62), 

nearly all covered pneumatic devices 

(continuous bleed and intermittent vent) 

would be required to have a methane 

and volatile organic compound (VOC) 

emission rate of zero. The only 

exception would be for pneumatic 

devices in Alaska at locations where onsite power is not available, in which 

case owners and operators would be 

required to use low bleed pneumatic 

devices in place of high bleed 

pneumatic devices (unless a high bleed 

device is needed for a functional need 

such as safety), and to verify that any 

intermittent bleed pneumatic devices 

operate such that they do not vent when 

idle by monitoring these devices during 

the fugitive emissions survey. 

We envision relatively few 

intermittent bleed pneumatic devices 

under the proposed zero-emission 

standard and presumptive standard for 

these pneumatic devices, compliance 

with which would require the use of 

non-emitting devices. As noted in the 

previous paragraph, we proposed in 

NSPS OOOOb and EG OOOOc to 

require periodic monitoring of those few 

intermittent bleed pneumatic devices. In 

addition, as noted in section III.J of this 

preamble, the proposed amendments 

that would apply to sources subject to 

the NSPS OOOOb and approved state 

plans or applicable Federal plan in 40 

CFR part 62 would not become effective 

for individual reporters unless and until 

their emission sources become subject 

to and are required to comply with 

either the final NSPS OOOOb or an 


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36964 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

67As noted previously, the development of the 

current emission factors for natural gas pneumatic 

devices is described in Greenhouse Gas Emissions 

Reporting from the Petroleum And Natural Gas 

Industry: Background Technical Support 

Document, U.S. EPA, November 2010, (Docket Id. 

No. EPA–HQ–OAR–2009–0923–3610), also 

available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

68The development of the emission factor for 

natural gas pneumatic pumps is described in 

Greenhouse Gas Emissions Reporting from the 

Petroleum And Natural Gas Industry: Background 

Technical Support Document, U.S. EPA, November 

2010, (Docket Id. No. EPA–HQ–OAR–2009–0923– 

3610), also available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

approved state plan or applicable 

Federal plan in 40 CFR part 62. Prior to 

that time, a reporter may elect to 

conduct inspections or surveys of their 

intermittent bleed pneumatic devices. 

Therefore, similar to the 2016 

amendments to subpart W (81 FR 4987, 

January 29, 2016), the EPA is proposing 

amendments to subpart W to provide an 

alternative methodology to calculate 

emissions from intermittent bleed 

pneumatic devices based on the results 

of inspections or surveys, consistent 

with section II.A.2 of this preamble. 

Specifically, for facilities that would be 

required to inspect their intermittent 

bleed pneumatic devices requirements 

under NSPS OOOOb or an approved 

state plan or the applicable Federal plan 

in 40 CFR part 62 (to the extent there 

are any) or facilities that elect to 

conduct routine monitoring surveys of 

their existing natural gas intermittent 

bleed pneumatic devices consistent 

with the methods in NSPS OOOOb prior 

to becoming subject to 40 CFR part 62, 

we are proposing to provide an 

alternative calculation methodology 

analogous to a ‘‘leaker factor’’ approach 

used for equipment leaks. Reporters 

using this calculation methodology 

would report the total number of natural 

gas intermittent bleed pneumatic 

devices at the facility, the frequency of 

monitoring, the number of devices 

found to be malfunctioning, and the 

average time the malfunctioning devices 

were malfunctioning. For more 

information regarding this proposed 

alternative calculation methodology for 

natural gas intermittent bleed 

pneumatic devices, see the subpart W 

TSD, available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. 

Hours of operation of natural gas 

pneumatic devices and natural gas 

driven pneumatic pumps. In 

correspondence with the EPA via eGGRT, reporters have indicated that 

there is confusion over the use of the 

term ‘‘operational’’ in the definition of 

variable ‘‘Tt’’ in equation W–1 in 40 CFR 

98.233(a) and the term ‘‘in operation’’ in 

the reporting requirements in 40 CFR 

98.236(b)(2). Both the current emission 

factors and the proposed updated 

emission factors described earlier in this 

section for natural gas pneumatic 

devices were developed by taking both 

periods of actuation and periods 

without actuation into account; 67 in 

other words, the emission factors are 

population emission factors. To 

calculate emissions accurately using a 

population emission factor, the average 

number of hours used in equation W– 

1 should be the number of hours that 

the devices of a particular type are in 

service (i.e., the devices are receiving a 

measurement signal and connected to a 

natural gas supply that is capable of 

actuating a valve or other device as 

needed). Therefore, consistent with 

section II.A.5 of this preamble, we are 

proposing to revise the definition of 

variable ‘‘Tt’’ in equation W–1 and the 

corresponding reporting requirement in 

40 CFR 98.236(b)(2) to use the term ‘‘in 

service (i.e., supplied with natural gas)’’ 

rather than ‘‘operational’’ or ‘‘in 

operation.’’ 

Similarly, the population emission 

factor for natural gas driven pneumatic 

pumps was developed using 

measurements taken during actuations 

together with manufacturer data and 

observed operational data at facilities 

(e.g., pump actuation rate).68 In other 

words, the emission factor represents 

the average emissions over the period 

when the pump is operating, not just the 

emissions during periods when the 

pump was actuating. Therefore, we are 

also proposing to revise the definition of 

variable ‘‘T’’ in equation W–2 in 40 CFR 

98.233(c)(1) for natural gas driven 

pneumatic pumps to use the term ‘‘in 

service (i.e., supplied with natural gas),’’ 

and we are proposing to use that same 

term in the corresponding reporting 

requirement in proposed 40 CFR 

98.236(c)(4). 

b. Natural Gas Driven Pneumatic Pump 

Venting 

The current procedures in subpart W 

for calculating and reporting emissions 

from natural gas driven pneumatic 

pump venting are specified in 40 CFR 

98.233(c) and 40 CFR 98.236(c). The 

inputs to equation W–2 in 40 CFR 

98.233(c) are the total number of natural 

gas driven pneumatic pumps and 

average estimated number of hours in 

the operating year the pumps were 

operational. Reporters then report these 

inputs along with the emissions under 

40 CFR 98.236(c). As the calculated 

emissions are vented emissions from 

natural gas driven pneumatic pumps, 

the intent is that the total number of 

natural gas driven pneumatic pumps 

should include only those pumps that 

are vented directly to the atmosphere 

(i.e., uncontrolled). However, based on 

contact with reporters, we understand 

that emissions from some natural gas 

driven pneumatic pumps are routed to 

controls, particularly flares or 

combustion units. Flared emissions 

from natural gas driven pneumatic 

pumps are not required to be calculated 

and reported separately from other 

flared emissions. Instead, emission 

streams from natural gas driven 

pneumatic pumps that are routed to 

flares are required to be included in the 

calculation of total emissions from the 

flare according to the procedures in 40 

CFR 98.233(n) and reported as part of 

the total flare stack emissions according 

to the procedures in 40 CFR 98.236(n), 

in the same manner as emission streams 

from other source types that are routed 

to the flare. Similarly, emissions from 

natural gas driven pneumatic pumps 

that are routed to a combustion unit are 

required to be combined with other 

streams of the same fuel type and used 

to calculate total emissions from the 

combustion unit as specified in 40 CFR 

98.233(z) and reported as part of the 

total emissions from the combustion 

unit as specified in 40 CFR 98.236(z). 

In correspondence with the EPA via eGGRT, some reporters have expressed 

confusion regarding the requirements 

for natural gas driven pneumatic pumps 

that are routed to flares or combustion 

devices, particularly between 40 CFR 

98.236(c) (for vented emissions) and 40 

CFR 98.236(n) or (z) (for flared or 

combusted emissions, respectively). 

Additionally, the counts of controlled 

natural gas driven pneumatic pumps 

currently are not reported separately 

from counts of vented natural gas driven 

pneumatic pumps under 40 CFR 

98.236(c), and the emissions currently 

reported from flares and combustion 

units are not attributed specifically to 

natural gas driven pneumatic pumps. 

This lack of reported information leads 

to uncertainty in verification of reported 

data when there are significant changes 

in reported data at a facility from one 

year to the next, which can result in 

additional communication with the 

reporter to clarify whether or not the 

changes are an error. The lack of 

reported information also means 

changes in the trends related to 

implementation of such controls relative 

to trends in overall use of natural gas 

driven pneumatic pumps in the 

petroleum and natural gas systems 

source category would be difficult to 

track. In addition, there are other rules 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 36965 

69American Petroleum Institute (API). Liquefied 

Natural Gas (LNG) Operations Consistent 

Methodology for Estimating Greenhouse Gas 

Emissions. Prepared for API by The LEVON Group, 

LLC. Version 1.0, May 2015. Available in the docket 

for this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

that require the control of pneumatic 

pumps (e.g., NSPS OOOOa), so we 

expect that there will be an increase in 

the number of natural gas driven 

pneumatic pumps that are routed to 

controls as more facilities become 

subject to those rules. 

Thus, consistent with section II.A.2 of 

this preamble, we are proposing to 

revise 40 CFR 98.233(c) to clarify 

requirements for calculating emissions 

from both natural gas driven pneumatic 

pumps that are vented to the 

atmosphere and controlled natural gas 

driven pneumatic pumps that are 

consistent with the intent of the current 

rule. Specifically, we are proposing to 

revise 40 CFR 98.233(c) introductory 

text and the definitions of the terms 

‘‘Count’’ and ‘‘T’’ in equation W–2 to 

further clarify that the provisions of 40 

CFR 98.233(c)(1) and (2) should only be 

used to calculate emissions from natural 

gas driven pneumatic pumps venting 

directly to the atmosphere. We are 

proposing to add 40 CFR 98.233(c)(3) to 

specify that if the emissions are flared, 

then flared emissions would be 

calculated using the method for flare 

stack emissions in 40 CFR 98.233(n) and 

reported as flare stack emissions under 

40 CFR 98.236(n). If emissions are 

routed to a combustion device, then 

emissions would be calculated using the 

methods for combustion devices as 

specified in 40 CFR 98.233(z) and 

reported as specified in 40 CFR 

98.236(z). Finally, if the emissions are 

routed to vapor recovery and are not 

subsequently routed to a combustion 

device, then we are proposing that 

reporters would not calculate or report 

emissions. If a natural gas driven 

pneumatic pump is vented directly to 

the atmosphere for part of the year and 

routed to a flare, combustion, or vapor 

recovery system during another part of 

the year, the reporter would calculate 

emissions using all applicable 

procedures and adjust the number of 

hours used in equation W–2 as needed. 

We request comment on whether 

pneumatic pumps are routed to vapor 

recovery systems and whether there are 

other controls that should be addressed 

with these new provisions. In addition, 

we request comment on whether flared 

emissions associated with natural gas 

driven pneumatic pumps should 

continue to be reported as flare stack 

emissions under 40 CFR 98.236(n) or 

should be reported in the natural gas 

driven pneumatic pumps emission 

source under 40 CFR 98.236(c). 

We are also proposing to add new 

reporting elements in 40 CFR 98.236(c) 

to align with the proposed clarifications 

to the emission calculation procedures. 

Specifically, we are proposing to 

expand the current requirement to 

report the total count of natural gas 

driven pneumatic pumps to three 

separate counts: the number of natural 

gas driven pneumatic pumps that are 

vented directly to atmosphere (i.e., 

uncontrolled); the number of natural gas 

driven pneumatic pumps that are routed 

to a flare, combustion, or vapor recovery 

(i.e., controlled); and the total number of 

natural gas driven pneumatic pumps at 

the facility. The total count of 

pneumatic pumps is a proposed 

reporting element along with the counts 

of uncontrolled and controlled 

pneumatic pumps because the total 

count would not always be equal to the 

sum of the other two counts. For 

example, a reporter that switches from 

one scenario to another during a year for 

a particular pneumatic pump (e.g., from 

vented to flared) would include that 

pneumatic pump in the count of pumps 

that vent directly to atmosphere and in 

the count of pumps that are routed to 

flares, but that pneumatic pump would 

only be counted once towards the total 

number of pneumatic pumps. The 

number of pneumatic pumps vented 

directly to the atmosphere would be 

equal to the ‘‘Count’’ in equation W–2 

and would be used in the verification of 

annual reports to the GHGRP. The total 

count of pneumatic pumps at the 

facility and the number of pneumatic 

pumps that are routed to a flare, 

combustion, or vapor recovery would 

provide the EPA with information to 

better characterize emissions from this 

source, including how many pneumatic 

pumps are controlled across the 

industry, how often pneumatic pumps 

are both controlled and vented directly 

to the atmosphere in the same year, and 

how the use of controls for pneumatic 

pumps changes across multiple years. 

c. Acid Gas Removal Vents 

Acid Gas Removal Units at LNG 

Import/Export Facilities. Emissions 

from acid gas removal units are 

currently reported for three industry 

segments: Onshore Petroleum and 

Natural Gas Production, Onshore 

Natural Gas Processing, and Onshore 

Petroleum and Natural Gas Gathering 

and Boosting. However, prior to 

becoming LNG, natural gas is treated to 

specifications more stringent than 

pipeline quality natural gas to remove 

nearly all of the heavy hydrocarbons, 

mercury, CO2, sulfur compounds, and 

other impurities to prevent problems 

with the liquefaction process (e.g., CO2

and hydrogen sulfide can cause freezing 

and plugging in downstream units once 

the gas is liquefied). Therefore, 

liquefaction plants at LNG export 

facilities may include acid gas removal 

units, and those emissions are not 

currently reported to the GHGRP if the 

acid gas removal unit vents are vented 

directly to the atmosphere. Emissions 

from acid gas removal unit vents that 

are routed to flares or thermal oxidizers 

that meet the subpart W definition of 

flare in 40 CFR 98.238 are reported 

under the flare stacks emission source, 

but they are not characterized as acid 

gas removal emissions. LNG export 

facilities may receive natural gas that 

has already been treated in a natural gas 

processing plant as well as raw material 

from dedicated gas fields, so the 

emissions from acid gas removal units at 

these facilities can comprise a 

significant portion of the facility’s 

emissions if the gas received at an LNG 

export facility has a relatively high CO2

content.69

Therefore, consistent with section 

II.A.3 of this preamble, the EPA is 

proposing to revise 40 CFR 98.232(h) 

and 40 CFR 98.236(a)(7) to add acid gas 

removal vents to the list of emission 

sources for which facilities in the LNG 

Import/Export industry segment must 

calculate and report emissions. 

Facilities in this industry segment with 

an acid gas removal unit would use one 

of the four calculation methods 

currently provided in 40 CFR 98.233(d) 

and report emissions as currently 

provided in 40 CFR 98.236(d). Facilities 

in this industry segment without an acid 

gas removal unit would only be required 

to indicate that in their report. We 

request comment on whether all four 

calculation methods currently provided 

in 40 CFR 98.233(d) are appropriate for 

facilities in the LNG Import/Export 

industry segment and if not, how 

specific calculation methods could be 

adjusted to be more applicable to this 

industry segment. In addition, we 

request comment on whether there are 

other emission sources at LNG Import/ 

Export facilities with significant 

emissions that should be added to 

subpart W (e.g., glycol dehydrators), as 

well as whether there are other industry 

segments with acid gas removal units 

that are not reported and make up a 

significant portion of facility emissions. 

Calculation method 4 reporting. 

Reporters with acid gas removal units 

that elect to calculate emissions using 

Calculation Method 4 are required to 

report several data elements that are 

inputs to the simulation software 

package that is used to calculate 


jspears on DSK121TN23PROD with PROPOSALS2
36966 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

70AspenTech HYSYS® software available from 

AspenTech website (https://www.aspentech.com/). 71 GRI–GLYCalcTM software available from Gas 

Technology Institute website (https://

sales.gastechnology.org/). 

72 GPA Midstream Association. Presentation 

slides regarding three alternatives for possible 

development of emission factors for large glycol 

dehydrators. November 20, 2019. Available in the 

docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

emissions. One of the required inputs to 

report is the solvent weight, in pounds 

per gallon (40 CFR 98.236(d)(2)(iii)(L)). 

A variety of different solvents may be 

used in an acid gas removal unit (e.g., 

chemical solvents such as 

monoethanolamine (MEA) and methyl 

diethanolamine (MDEA), physical 

solvents such as SelexolTM and 

Rectisol®), and the solubility of CO2

varies across the different types of 

solvent. Requiring reporters to provide 

solvent characteristics provides 

information about the type of solvent 

used so the emissions calculated by the 

modeling run could be verified. 

However, the ‘‘solvent weight’’ is the 

only data element related to the 

identification of the solvent that is 

currently collected, and the values 

reported across all reporters have been 

inconsistent over the last few years, 

indicating that this data element is 

likely not clear to reporters (e.g., some 

reporters appear to be providing the 

density of the solvent and others appear 

to be providing the amine concentration 

in weight percent). In addition, the 

densities of common amine-based 

solvents are fairly close in value, so 

even among reporters that are providing 

values within the expected range of 

solvent densities, we have found it 

difficult to use this data element to 

identify the solvent type. Finally, the 

current requirement to report solvent 

weight does not specify how this value 

should be determined, but given the 

precise values being reported, it appears 

that reporters are either measuring the 

solvent or reporting a specific value 

provided by the vendor. 

Therefore, we are proposing to replace 

the requirement to report solvent weight 

with a requirement to report the solvent 

type and, for amine-based solvents, the 

general composition. Reporters would 

choose the type/general composition 

option from a pre-defined list that most 

closely matches the solvent type and 

composition used in their acid gas 

removal unit. The standardized 

response options would include the 

following: ‘‘SelexolTM,’’ ‘‘Rectisol®,’’ 

‘‘PurisolTM,’’ ‘‘Fluor SolventSM,’’ 

‘‘BenfieldTM,’’ ‘‘20 wt% MEA,’’ ‘‘30 wt% 

MEA,’’ ‘‘40 wt% MDEA,’’ ‘‘50 wt% 

MDEA,’’ and ‘‘Other.’’ We are proposing 

to use commercially available trade 

names in this list rather than chemical 

compositions, as the trade names are 

more commonly used among acid gas 

removal unit operators and therefore 

more readily available. This proposed 

amendment to collect standardized 

information about the solvent is 

expected to result in more useful data 

that would improve verification of 

reported data and better characterize 

acid gas removal vent emissions, 

consistent with section II.A.4 of this 

preamble. It would also improve the 

quality of the data reported compared to 

the apparently inconsistent application 

of the current requirements. In addition, 

the solvent type and composition rarely 

change from one year to the next, so 

once the data element is reported the 

first time, most reporters would be able 

to copy the response from the previous 

year’s reporting form each year. 

Therefore, the proposal to require 

reporters to select a solvent type and 

composition from these standardized 

responses is also expected to streamline 

and improve implementation compared 

to the current requirement of reporting 

an exact value for solvent weight, 

consistent with section II.B.3 of this 

preamble. 

d. Dehydrator Vents 

Dehydrators are used to remove water 

from produced natural gas prior to 

transferring the natural gas into a 

pipeline or to a gas processing facility. 

Subpart W requires reporting of GHG 

emissions from dehydrator vents at 

onshore petroleum and natural gas 

production, onshore petroleum and 

natural gas gathering and boosting, and 

natural gas processing facilities. 

Emissions are determined using one of 

the calculation methodologies for glycol 

dehydrators provided in 40 CFR 

98.233(e) based on the unit’s annual 

average daily natural gas throughput. 

For units with an annual average daily 

natural gas throughput less than 0.4 

MMscf per day, reporters currently use 

population emission factors and 

equation W–5 to calculate volumetric 

CO2 and CH4 emissions per 40 CFR 

98.233(e)(2). For units with an annual 

average daily natural gas throughput 

greater than or equal to 0.4 MMscf per 

day, reporters must follow the 

provisions under 40 CFR 98.233(e)(1), 

which require modeling GHG emissions 

using a software program (e.g., 

AspenTech HYSYS® 70 or GRI– 

GLYCalcTM 71). 

The EPA has reviewed the subpart W 

glycol dehydrator data and reporting 

requirements in 40 CFR 98.236(e) and 

has made a preliminary determination 

that additional information would help 

to more accurately characterize 

emissions from glycol dehydrators with 

an annual average daily natural gas 

throughput greater than or equal to 0.4 

MMscf per day. Specifically, the EPA’s 

review found no strong correlations 

between glycol dehydrator emissions 

and the operating parameters currently 

reported under 40 CFR 98.236(e)(1). 

This assessment is consistent with the 

results of an analysis provided to the 

EPA by GPA Midstream, which 

indicated that the correlations between 

vent gas flow rate, glycol circulation 

rate, and glycol pump type provided the 

most accurate approximation of 

dehydrator emissions.72 While subpart 

W does currently collect information on 

glycol pump type and circulation rate 

for each modeled glycol dehydrator 

with an annual average daily natural gas 

throughput greater than or equal to 0.4 

MMscf per day, reporters are not asked 

to report any characteristics of their 

units’ flash tank and still vents, 

including vent gas flow rate. As such, 

the EPA is not able to review historical 

subpart W dehydrator data to verify 

GPA Midstream’s suggested correlation 

between vent gas flow rate, glycol 

circulation rate, and glycol pump type. 

Therefore, the EPA is proposing to add 

new reporting requirements to 40 CFR 

98.236(e)(1), consistent with section 

II.A.4 of this preamble. The following 

new data elements are proposed to be 

added to subpart W for glycol 

dehydrators with an annual average 

daily natural gas throughput greater 

than or equal to 0.4 MMscf per day: 

• Flash tank control technique 

• Regenerator still vent control 

technique 

• Flash tank vent gas flow rate 

(standard cubic feet per hour (scfh)) 

• Regenerator still vent gas flow rate 

(scfh) 

• Concentrations of CH4 and CO2 in 

flash tank vent gas (mole fraction) 

• Concentrations of CH4 and CO2 in 

regenerator still vent gas (mole 

fraction) 

• Type of stripping gas used 

• Flow rate of stripping gas (standard 

cubic feet per minute (scfm)) 

These proposed additional data 

elements are intended to allow the EPA 

to derive a correlation between vent 

flow rate and absorbent circulation rate 

and better characterize emissions from 

glycol dehydrators with an annual 

average daily natural gas throughput 

greater than or equal to 0.4 MMscf per 

day. Further, the EPA is proposing to 

require separate reporting of emissions 

for a modeled glycol dehydrator’s still 

vent and flash tank vent. These vents 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 36967 

73Zaimes, G.G. et al. ‘‘Characterizing Regional 

Methane Emissions from Natural Gas Liquid 

Unloading.’’ Environ. Sci. Technol. 2019, 53, 4619– 

4629. Available in the docket for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424. 

often use different control techniques, 

so requiring the emissions from these 

vents to be reported separately would 

ensure that future analyses accurately 

characterize the emissions. The 

proposed data elements are included in 

the output files from the modeling 

software used for glycol dehydrators 

and are, therefore, not expected to be 

difficult for reporters to implement. 

Additionally, in correspondence with 

the EPA via e-GGRT, some reporters 

have expressed confusion regarding the 

requirements for glycol dehydrators 

emissions that are routed to vapor 

recovery and subsequently routed to a 

flare or regenerator firebox/fire tubes. As 

such, the EPA is proposing edits to the 

vapor recovery calculation methodology 

of 40 CFR 98.233(e)(5) (proposed to be 

moved to 40 CFR 98.233(e)(4)) to clarify 

that unrecovered emissions that are not 

routed to flares or regenerator fireboxes/ 

fire tubes should be reported as 

emissions vented directly to 

atmosphere, while emissions that are 

routed to flares or regenerator fireboxes/ 

fire tubes should be reported as flared 

emissions from dehydrators. Along with 

the proposed amendments to 40 CFR 

98.233(e)(6) (proposed to be moved to 

40 CFR 98.233(e)(5)) for calculating 

emissions from flares or regenerator 

fireboxes/fire tubes (discussed in 

section III.J.1.i of this preamble), the 

EPA seeks to enhance the overall quality 

of the data collected under the GHGRP, 

consistent with section II.A.5 of this 

preamble. 

e. Liquids Unloading 

Subpart W currently requires 

reporting of emissions from well venting 

for liquids unloading. Facilities 

calculate emissions using measured 

flow rates under Calculation Method 1 

(40 CFR 98.233(f)(1)) or engineering 

equations under Calculation Method 2 

for unloadings without plunger lifts (40 

CFR 98.233(f)(2)) and Calculation 

Method 3 for unloadings with plunger 

lifts (40 CFR 98.233(f)(3)). Under the 

reporting requirements of 40 CFR 

98.236(f), facilities must report whether 

plunger lifts were used when using 

Calculation Method 1 and must report 

the data elements used in equations W– 

7A and W–7B. For Calculation Methods 

2 and 3, however, reporters only report 

a subset of the data elements used to 

calculate emissions in equations W–8 

and W–9. Specifically, for Calculation 

Methods 2 and 3, reporters must 

provide a plunger lift indicator (i.e., 

whether plunger lifts were used), total 

number of wells with well venting for 

liquids unloading, the total number of 

unloading events, and the casing 

diameter (Calculation Method 2) or the 

tubing diameter (Calculation Method 3). 

In a 2019 study, Zaimes et al.73

evaluated various liquid unloading 

scenarios, and the results indicated that 

differentiating emissions only on the 

basis of type of unloading (plunger or 

non-plunger lift) may not accurately 

assess emissions from this source. In 

particular, Zaimes et al. noted that type 

of unloading should be further 

differentiated for plunger lift unloadings 

between automated and manual 

unloadings, suggesting further 

granularity is necessary to properly 

characterize emissions. In particular, 

there could be significant differences in 

the number and duration of unloadings 

and, hence, differences in emissions 

between manual and automated plunger 

lift unloadings and liquids unloading 

emissions. 

The Zaimes et al. study did not 

evaluate manual and automated nonplunger lift unloadings separately, but 

further differentiating non-plunger lift 

unloadings between manual and 

automated unloadings in subpart W 

could also improve data quality. 

Correspondence with reporters via eGGRT since subpart W reporting for the 

onshore production segment began in 

2011 indicates potentially significant 

differences in the number of unloadings 

and emissions for manual versus 

automated non-plunger lift unloadings. 

When the EPA finalized the calculation 

methods and reporting requirements for 

well venting for liquids unloading, the 

reporting requirements did not 

differentiate between manual and 

automated non-plunger lift unloadings. 

However, reporters have clearly 

affirmed the use of automated nonplunger lift unloadings in response to 

multiple inquiries the EPA has made as 

part of the annual report verification 

process. 

In addition, there are several data 

elements used to calculate emissions 

from liquids unloading in equations W– 

8 and W–9 for Calculation Methods 2 

and 3 that are not currently required to 

be provided. Specifically, reporters do 

not report well depth (Calculation 

Method 2) or tubing depth (Calculation 

Method 3), the average flow-line rate of 

gas, the hours that wells are left open to 

the atmosphere during unloading 

events, and the shut-in, surface or 

casing pressure (Calculation Method 2) 

or the flow-line pressure (Calculation 

Method 3). Requiring reporting of these 

data elements would improve 

verification of annual reports to the 

GHGRP and would allow the EPA and 

the public to replicate calculations and 

more confidently confirm reported 

calculated emissions than is currently 

possible. 

The EPA is, therefore, proposing to 

revise the reporting requirements in 40 

CFR 98.236(f)(1) and (2) to require 

reporters to include the following data 

elements, consistent with section II.A.4 

of this preamble. In 40 CFR 98.236(f)(1), 

for Calculation Method 1, the EPA is 

proposing that reporters would identify 

the type of unloading as an automated 

or manual unloading in addition to 

identifying whether the unloading is a 

plunger lift or non-plunger lift 

unloading. We are also proposing that 

reporters would report emissions from 

automated unloadings separately from 

manual unloadings. In addition, for 

each individual Calculation Method 1 

well that was tested during the year, we 

are proposing that reporters would 

specify the type of unloading as an 

automated or manual unloading under 

40 CFR 98.236(f)(1)(xi)(F) or 40 CFR 

98.236(f)(1)(xii)(F), as applicable. 

For non-plunger lift unloadings that 

use Calculation Method 2 in 40 CFR 

98.233(f)(2), the EPA is proposing that 

reporters would identify the type of 

non-plunger lift unloading as an 

automated or manual non-plunger lift 

unloading and that reporters would 

report emissions and activity data 

separately for each unloading type. In 

addition, for all non-plunger lift 

unloadings, the EPA is proposing to add 

requirements in 40 CFR 98.236(f)(2)(ix) 

(proposed to be moved to 40 CFR 

98.236(f)(2)(xi)) to report the average 

well depth for all wells in the sub-basin 

(WDp) and the average shut-in pressure 

or surface pressure for wells with tubing 

production, or average casing pressure 

for wells with no packers for all wells 

in the sub-basin (SPp). 

For plunger lift unloadings that use 

Calculation Method 3 in 40 CFR 

98.233(f)(3), the EPA is proposing that 

reporters would identify the type of 

plunger lift unloading as an automated 

or manual plunger lift unloading and 

that reporters would report emissions 

and activity data separately for each 

unloading type. In addition, for all 

plunger lift unloadings, the EPA is 

proposing to add requirements in 40 

CFR 98.236(f)(2)(x) (proposed to be 

moved to 40 CFR 98.236(f)(2)(xii)) to 

report the average tubing depth to 

plunger bumper for all wells in the subbasin (WDp) and the average flow-line 

pressure for all wells in the sub-basin 

(SPp). Finally, for all unloadings that use 

Calculation Method 2 or 3, the EPA is 

proposing to add requirements in 40 


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CFR 98.236(f)(2)(ix) and (x) to report the 

average flow-line rate of gas for all wells 

in the sub-basin (SFRp) and cumulative 

number hours that all wells in the subbasin are left open to the atmosphere 

during unloading events (HRp,q), 

respectively. 

f. Blowdown Vent Stacks 

Subpart W currently requires 

reporting of blowdowns either using 

flow meter measurements (40 CFR 

98.233(i)(3)) or using unique physical 

volume calculations by equipment or 

event types (40 CFR 98.233(i)(2)). 

Stakeholders have indicated that there 

is some confusion regarding the 

reference to ‘‘distribution’’ pipelines in 

the descriptions of the ‘‘facility piping’’ 

and ‘‘pipeline venting’’ categories 

because compressor stations are not 

associated with distribution pipelines. 

Therefore, the EPA is proposing to 

revise the descriptions of the facility 

piping and pipeline venting categories 

to reduce confusion regarding which 

equipment or event type category is 

appropriate for each blowdown, 

consistent with section II.A.5 of this 

preamble. Our intent is that the ‘‘facility 

piping’’ equipment category is limited 

to unique physical volumes of piping 

(i.e., piping between isolation valves) 

that are located entirely within the 

facility boundary. Conversely, the intent 

for the ‘‘pipeline venting’’ equipment 

category is that a portion of the unique 

physical volume of pipeline is located 

outside the facility boundary and the 

remainder, including the blowdown 

vent stack, is located within the facility 

boundary. The proposed revisions to the 

equipment type descriptions would 

clarify these distinctions. Additionally, 

we are proposing to remove the 

reference to ‘‘distribution’’ pipelines 

because we did not intend to limit the 

pipeline venting category to unique 

physical volumes that include such 

pipelines. We agree with the industry 

stakeholders that facilities subject to the 

blowdown vent stack reporting 

requirements typically are connected to 

other pipelines such as gathering 

pipelines or transmission pipelines, and 

on-site blowdowns from sections of 

these pipelines should be reported. 

Finally, we note that for the ‘‘facility 

piping’’ equipment category and the 

‘‘pipeline venting’’ equipment category, 

the phrase ‘‘located within a facility 

boundary’’ generally refers to being part 

of the facility as defined by the existing 

provisions of subpart A or subpart W, as 

applicable. In other words, blowdowns 

from unique physical volumes of 

gathering pipeline that are entirely 

considered to be part of the ‘‘facility 

with respect to onshore petroleum and 

natural gas gathering and boosting’’ as 

defined in 40 CFR 98.238 would be 

assigned to the ‘‘facility piping’’ 

equipment category. The ‘‘pipeline 

venting’’ equipment category would 

only apply if the unique physical 

volume includes some sections of 

gathering pipelines that are not part of 

the ‘‘facility with respect to onshore 

petroleum and natural gas gathering and 

boosting’’ as defined in 40 CFR 98.238. 

g. Atmospheric Storage Tanks 

Open thief hatches. Facilities in the 

Onshore Petroleum and Natural Gas 

Production and Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segments are required to report 

CO2 and CH4 emissions (and N2O 

emissions when flared) from 

atmospheric pressure fixed roof storage 

tanks receiving hydrocarbon liquids 

(hereafter referred to as ‘‘atmospheric 

storage tanks’’). The purpose of a thief 

hatch on an atmospheric storage tank is 

generally to allow access to the contents 

of the tank for sampling, gauging, and 

determining liquid levels. The thief 

hatch also works along with the vent 

valve to maintain pressure on the tank 

while preventing excessive vacuum 

from collapsing the tank. The EPA 

previously evaluated emissions from 

atmospheric storage tanks as part of the 

2016 amendments to subpart W (81 FR 

86500, November 30, 2016) and 

determined that the subpart W 

calculation methodology in 40 CFR 

98.233(j) already includes emissions 

from thief hatches or other openings on 

atmospheric storage tanks in the 

Onshore Petroleum and Natural Gas 

Production and Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segments. The subpart W 

calculation methodologies for controlled 

atmospheric storage tanks include 

procedures for determining emissions 

from storage tanks with a vapor recovery 

system (40 CFR 98.233(j)(4)) and storage 

tanks with a flare (40 CFR 98.233(j)(5)). 

The procedure for determining 

emissions from a tank with a vapor 

recovery system instructs reporters to 

adjust the storage tank emissions 

downward by the magnitude of 

emissions recovered using a vapor 

recovery system as determined by 

engineering estimate based on best 

available data (40 CFR 98.233(j)(4)(i)). 

The procedure for determining 

emissions from an atmospheric storage 

tank with a flare references 40 CFR 

98.233(n), which instructs reporters to 

use engineering calculations based on 

process knowledge, company records, 

and best available data to determine the 

flow to the flare if the flare does not 

have a continuous flow measurement 

device. If a reporter sees emissions from 

a thief hatch or other opening on a 

controlled atmospheric storage tank 

during an equipment leak survey 

conducted using OGI, the reporter 

should consider that information as part 

of the ‘‘best available data’’ used to 

calculate emissions from that storage 

tank. 

However, it appears that emissions 

from open thief hatches on atmospheric 

storage tanks may not be accurately 

portrayed in subpart W, as many 

reporters claim 100 percent capture 

efficiency from vapor recovery systems 

and flares. In order to alleviate any 

reporting confusion, the EPA is 

proposing several clarifying edits to 40 

CFR 98.233(j)(4) and (5), consistent with 

section II.A.5 of this preamble. We are 

proposing to specifically state in each 

paragraph that emissions during times 

of reduced capture efficiency are 

required to be evaluated to determine if 

adjustments are needed to the 

calculated recovered mass from vapor 

recovery units or flare feed gas volumes. 

Reduced capture efficiency may occur 

during periods when the control device 

is not operating or is bypassed and at 

times when the control device is 

operating, such as open thief hatches. 

The emissions that are not captured by 

a vapor recovery system or sent to a 

flare must be considered when 

calculating emissions from atmospheric 

storage tanks vented directly to the 

atmosphere. 

The EPA is also proposing revisions 

to the atmospheric storage tank 

reporting requirements in 40 CFR 

98.236(j) with regard to open thief 

hatches. Specifically, the EPA is 

proposing to require reporting of the 

number of controlled tanks with open or 

unseated thief hatches within the 

reporting year, as well as the total 

volume of gas vented through the open 

or unseated thief hatches. With these 

new reporting elements, the EPA seeks 

to quantify the impact of open thief 

hatches on atmospheric storage tanks 

and enhance the overall quality of the 

data collected under the GHGRP, 

consistent with section II.A.4 of this 

preamble. 

Malfunctioning dump valves and 

atmospheric storage tanks with flares. 

For Onshore Petroleum and Natural Gas 

Production and Onshore Petroleum and 

Natural Gas Gathering and Boosting 

facilities with atmospheric storage tank 

emissions calculated using Calculation 

Method 1 (40 CFR 98.233(j)(1)) or 

Calculation Method 2 (40 CFR 

98.233(j)(2)), reporters must also follow 

the procedures in 40 CFR 98.233(j)(6) 

and use equation W–16 to calculate 

emissions from occurrences of gasVerDate Sep<11>2014 20:28 Jun 17, 2022 Jkt 256001 PO 00000 Frm 00050 Fmt 4701 Sfmt 4702 E:\FR\FM\21JNP2.SGM 21JNP2

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liquid separator dump valves not 

closing properly. Equation W–16 

estimates the annual volumetric GHG 

emissions at standard conditions from 

each storage tank resulting from the 

malfunctioning dump valve on the gasliquid separator using a correction 

factor, the total time the dump valve did 

not close properly in the calendar year, 

and the hourly storage tank emissions. 

Per the definition of the variable ‘‘En’’ in 

equation W–16, the input hourly storage 

tank emissions should be those 

calculated using Calculation Methods 1 

or 2 and should be adjusted downward 

by the magnitude of emissions 

recovered using a vapor recovery 

system, if applicable. However, the 

definition of the variable ‘‘En’’ in 

equation W–16 does not include the 

procedure to be used for emissions from 

malfunctioning dump valves and 

atmospheric storage tanks that are 

flared. In order to address any confusion 

for reporters, the EPA is proposing to 

amend the definition of the variable 

‘‘En’’ in equation W–16 to include flared 

storage tank emissions as determined in 

paragraph 40 CFR 98.233(j)(5), 

consistent with section II.A.5 of this 

preamble. The EPA is also proposing to 

revise the equation variables 

(particularly the subscripts) in equation 

W–16 to clarify the intent of this 

equation. We are proposing to revise the 

variable ‘‘En’’ to ‘‘Es,i’’ to further clarify 

that these are the volumetric 

atmospheric storage tank emissions 

determined using the procedures in 40 

CFR 98.233(j)(1) through (5). We are also 

proposing to replace the ‘‘n’’ and ‘‘p’’ 

subscripts in the other variables with a 

‘‘dv’’ subscript to indicate that these are 

the emissions from periods when the 

gas-liquid separator dump valves were 

not closed properly and that the 

emissions from these periods should be 

added to the emissions determined 

using the procedures in 40 CFR 

98.233(j)(1) through (5). 

Composition of hydrocarbon liquids. 

Under 40 CFR 98.236(j)(1)(vii) and (viii), 

reporters with atmospheric storage tank 

emissions calculated using Calculation 

Method 1 or Calculation Method 2 are 

required to provide the minimum and 

maximum concentrations (mole 

fractions) of CO2 and CH4 in the tank 

flash gas. Reporting of emissions and 

activity data for atmospheric storage 

tanks is aggregated at the sub-basin or 

county level, and the minimum and 

maximum flash gas concentrations were 

expected to provide the EPA with a 

broad characterization of the oftensignificant number of tanks reported for 

each sub-basin or county. However, 

through correspondence with reporters 

via e-GGRT, the EPA has found that the 

minimum and maximum flash gas 

concentrations do not accurately 

represent the majority of atmospheric 

storage tanks within the reported subbasins and counties. Thus, the EPA is 

proposing to revise these two reporting 

requirements to request the flowweighted average concentration (mole 

fraction) of CO2 and CH4 in the flash 

gas, rather than the minimum and 

maximum values. Consistent with 

section II.A.4 of this preamble, the EPA 

expects that these revisions would 

improve both the representative nature 

of the data collected and the process of 

verifying annual reported atmospheric 

storage tanks emissions data under the 

GHGRP. 

h. Associated Gas Venting and Flaring 

Associated gas venting. Associated 

gas venting or flaring is the venting or 

flaring of natural gas that originates at 

wellheads that also produce 

hydrocarbon liquids and occurs either 

in a discrete gaseous phase at the 

wellhead or is released from the liquid 

hydrocarbon phase by separation. 

Venting associated gas involves directly 

releasing associated gas into the 

atmosphere at the well pad or tank 

battery. Flaring associated gas is a 

common, and usually preferred, 

alternative to venting for safety and 

environmental reasons. Subpart W 

requires reporters to calculate annual 

emissions from associated gas venting 

and flaring using equation W–18, which 

uses the gas-to-oil ratio (GOR), volume 

of oil produced, and volume of 

associated gas sent to sales to calculate 

the volume of gas vented. Associated 

gas venting emissions are then 

calculated using the results of equation 

W–18 and the gas composition 

determined using 40 CFR 98.233(u), and 

associated gas flaring emissions are 

calculated by applying the calculation 

method of flare stacks in 40 CFR 

98.233(n) to the associated natural gas 

volume and gas composition 

determined for the associated gas stream 

routed to the flare. 

As discussed further in section III.J.1.i 

of this preamble, the EPA is proposing 

several amendments to the calculation 

and reporting requirements for flare 

stacks that would impact associated gas 

flaring emissions. One of the proposed 

amendments would provide for the use 

of continuous flow measurement 

devices for the purposes of calculating 

flared emissions. Similarly, for 

associated gas venting emissions, we are 

proposing provisions to specify that if a 

continuous flow measurement device is 

present, it must be used to determine 

the volume of gas vented rather than 

equation W–18. We are proposing 

corresponding reporting requirements 

for associated gas venting emissions, 

including requiring an indication of 

whether a continuous flow monitor or 

continuous composition analyzer was 

used and the flow-weighted mole 

fractions. Finally, we are proposing to 

specify that if all of the volumetric 

emissions from associated gas venting 

and flaring in the sub-basin were 

determined using a continuous flow 

measurement device rather than 

equation W–18 (i.e., equation W–18 was 

not used for any wells in the sub-basin), 

then reporting of the GOR, the volume 

of oil produced, and the volume of gas 

sent to sales for wells with associated 

gas venting or flaring is not required for 

that sub-basin. 

Oil and gas volumes. As noted 

previously in this section, subpart W 

requires reporters to calculate annual 

emissions from associated gas venting 

and flaring using equation W–18. Two 

of the inputs in the equation are the 

volume of oil produced and volume of 

associated gas sent to sales for each well 

in the sub-basin during time periods in 

which associated gas was vented or 

flared. However, based on the values 

reported, there seems to be confusion 

among some reporters regarding the 

inputs to these equations. For example, 

for some reporters, when the reported 

volume of gas sent to sales during time 

periods in which associated gas was 

vented or flared under 40 CFR 

98.236(m)(6) is summed across all subbasins at the facility, the total is the 

same as the total volume of gas sent to 

sales for the facility reported under 40 

CFR 98.236(aa)(1)(i)(B). If these 

reporters are accurately reporting the 

volume of gas sent to sales and using 

that volume in equation W–18, then the 

associated gas venting and flaring 

emissions are likely overstated, as it is 

unlikely that all wells are venting or 

flaring associated gas 100 percent of the 

time. If the reporters are using accurate 

volumes of gas sent to sales during time 

periods in which associated gas was 

vented or flared for their emissions 

calculations but reporting total gas sent 

to sales, then the activity data reported 

do not match the emissions, leading to 

an inconsistent data set. Therefore, the 

EPA is proposing to add the word 

‘‘only’’ to the definitions of the terms 

Vp,q and SGp,q in equation W–18 (40 CFR 

98.233(m)(3)) and to the reporting 

requirements for those data elements in 

40 CFR 98.236(m)(5) and (6). Consistent 

with section II.A.5 of this preamble, 

these proposed amendments would 

reduce reporter confusion regarding the 

volumes that should be used in the 


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74Flare stacks are an emission source type subject 

to emissions reporting by facilities in the following 

industry segments: Onshore Petroleum and Natural 

Gas Production, Onshore Petroleum and Natural 

Gas Gathering and Boosting, Onshore Natural Gas 

Processing, Onshore Natural Gas Transmission 

Compression, Underground Natural Gas Storage, 

LNG Import and Export Equipment, and LNG 

Storage. 

75Facilities separately calculate the flared 

emissions from the following types of emission 

sources (if required for the applicable industry 

segment, per 40 CFR 98.232): dehydrator vents, well 

venting during completions and workovers with 

hydraulic fracturing, gas well venting during 

completions and workovers without hydraulic 

fracturing, onshore production and onshore 

petroleum and natural gas gathering and boosting 

storage tanks, transmission storage tanks, well 

testing venting and flaring, and associated gas 

venting and flaring. 

76Letter from Matt Hite, GPA Midstream 

Association, to Mark de Figueiredo, U.S. EPA, Re: 

Additional Information on Suggested Part 98, 

Subpart W Rule Revisions to Reduce Burden. 

September 13, 2019. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

emissions calculations and the volumes 

that should be reported. 

i. Flare Stack Emissions 

Flare stacks are an emission source 

type subject to emissions reporting by 

facilities in seven of the ten industry 

segments in the Petroleum and Natural 

Gas Systems source category.74

Total CO2, CH4, and N2O emissions 

from each flare are required to be 

calculated using the methodology 

specified in 40 CFR 98.233(n). In 

addition to calculating total emissions 

from a flare, reporters must also 

separately calculate the flared emissions 

from several types of emission 

sources.75 The methodology for 

calculating source-specific flared 

emissions is specified in the applicable 

paragraph of 40 CFR 98.233 for each 

source type. The procedures in the 

source-specific paragraphs of the rule 

cross-reference the calculation 

procedures in 40 CFR 98.233(n), but 

they also specify that the volume and 

composition of the gas routed to the 

flare are required to be determined 

according to the procedures for 

estimating vented emissions from the 

specific source type. For example, 40 

CFR 98.233(e)(6) specifies that the 

volume and gas composition to use in 

calculating flared emissions from 

dehydrators must be determined 

according to the procedures for 

calculating vented emissions from 

dehydrators as specified in 40 CFR 

98.233(e)(1) through (5). Since sourcespecific flared emissions often are a 

portion of the total emissions from a 

flare, 40 CFR 98.233(n)(9) specifies that 

the total CO2, CH4, and N2O for a 

particular flare must be adjusted 

downward by the amount of the sourcespecific emissions that are calculated for 

the same flare; this ensures that 

emissions from a flare are not double 

counted (i.e., reported for both the flare 

stacks source type and another emission 

source type). The resulting CO2, CH4, 

and N2O emissions to report for that 

flare according to 40 CFR 98.236(n)(9) 

through (11) should be only what is left 

after subtracting all of the sourcespecific flared emissions from the total 

emissions. 

This calculation and reporting 

paradigm often means zero mass 

emissions are reported for the flare 

because all of the mass emissions are 

reported as flared emissions from other 

source types. However, even when the 

only streams routed to a flare are from 

source types that are subject to flared 

emissions reporting, the flare name or 

ID and all activity data related to the 

streams that are routed to the flare and 

the flare operating characteristics still 

must be reported under 40 CFR 

98.236(n). These activity data include 

the volume of gas routed to the flare, 

average CO2 and CH4 mole fractions in 

the flared gas, flare combustion 

efficiency, fraction of flared gas routed 

to the flare when it was unlit, and 

indicators of whether a continuous flow 

measurement device and a continuous 

gas analyzer were used on the gas 

stream routed to the flare. These flare ID 

and activity data reporting requirements 

are specified in 40 CFR 98.236(n)(1) 

through (8). In the rare cases that a 

CEMS is used on the outlet of a flare, 

then according to 40 CFR 98.236(n)(12), 

only the flare ID and the measured CO2

emissions must be reported. 

Reporting requirements for flared 

emissions. Many reporters have 

provided information through the 

GHGRP Help Desk and in 

correspondence with the EPA via eGGRT indicating that reporters are not 

interpreting the reporting requirements 

as written and as the EPA intended for 

flares that receive gas from sources that 

are subject to source-specific flared 

emissions reporting (e.g., atmospheric 

tanks). A key misconception is that the 

adjustment requirement in 40 CFR 

98.233(n)(9) applies to all flare data, not 

just the mass emissions (as intended). 

Thus, some reporters provide 

information for a flare only if some of 

the mass emissions from the flare are 

due to combustion of gas from source 

types that are not subject to sourcespecific flared emissions reporting (i.e., 

miscellaneous flared sources). Although 

these reporters generally correctly report 

the mass emissions from the flare that 

are due to the miscellaneous flared 

sources, they incorrectly limit their 

activity data reporting to those same 

streams. The EPA has procedures in its 

verification process to identify such 

errors; if errors are identified, the EPA 

notifies the reporter, who can resolve 

the issue by correcting the data and 

resubmitting their annual GHG report. 

Some reporters have also indicated that 

it is confusing to report activity data for 

a flare in one table in the reporting form 

(i.e., Table N.1), but to report the 

emissions in different tables; they 

suggest that it would be clearer to report 

all flare activity data and emissions 

related to a particular emission source 

type together in one location. One 

industry stakeholder, GPA Midstream, 

also suggested that flare activity data 

should be reported in the same manner 

that flared emissions are reported. In 

other words, instead of providing a 

single comprehensive record of the 

activity data per flare as is currently 

required by 40 CFR 98.236(n), the 

activity data for flared streams for a 

particular emission source (e.g., 

associated gas or atmospheric storage 

tanks) should be reported with the 

flared emissions for the same emission 

source type. According to GPA 

Midstream, this reporting approach 

would be simpler and easier for 

reporters to follow than the current 

requirements.76 We reviewed the flare 

reporting requirements based on this 

feedback, and we are proposing several 

revisions to the reporting requirements 

to improve the quality of the reported 

data, consistent with section II.A.4 of 

this preamble. 

First, we are proposing to modify the 

reporting requirements so that the 

existing requirements in 40 CFR 

98.236(n) would apply only to flares 

that receive gas from miscellaneous 

flared sources. The activity data to 

report would be limited to the streams 

from the miscellaneous flared sources, 

and the CO2, CH4, and N2O emissions to 

report would be the emissions that are 

calculated from combustion of the same 

streams. In addition, we would add 

comparable activity data reporting 

requirements to the reporting required 

for all of the source types for which 

flared emissions reporting is currently 

required (e.g., 40 CFR 98.236(e) for 

dehydrators, 40 CFR 98.236(g) for 

completions and workovers with 

hydraulic fracturing). The activity data 

reporting would be on the same basis as 

the emissions reporting. For example, 

activity data for glycol dehydrators with 

an annual average daily natural gas 

throughput greater than or equal to 0.4 

MMscf per day would be related to the 

flared streams from each dehydrator 

because flared emissions are reported 

per dehydrator. Activity data to be 


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reported for associated gas streams, on 

the other hand, would be aggregated 

over all associated gas streams routed to 

flares in a sub-basin because flared 

associated gas emissions are reported 

per sub-basin. In addition, for 

completions and workovers with 

hydraulic fracturing, flaring during the 

initial flowback period may not be 

possible; therefore, some of the wells 

that report as part of a ‘‘flared’’ well 

type combination because most of the 

gas is flared may also include emissions 

from gas that is vented before flaring 

begins. To improve our understanding 

of the characteristics of the ‘‘flared’’ 

emissions from completions and 

workovers with hydraulic fracturing, we 

are proposing that reporters would 

indicate in 40 CFR 98.236(g)(10)(i) 

whether the total emissions reported 

under 40 CFR 98.236(g)(8) and (9) 

include emissions from venting during 

the initial flowback period. These 

proposed amendments would better 

align the flared emissions and activity 

data for source types for which flared 

emissions reporting is currently 

required. 

Second, in the current rule, 40 CFR 

98.236(n)(7) and (8) require reporting of 

the CH4 and CO2 mole fractions in feed 

gas that are used in equations W–19 and 

W–20 to calculate total emissions from 

a flare. The intent was for reporters to 

provide the average values used to 

calculate total emissions from the flare. 

However, the rule language is not clear 

on this point, and it appears some 

reporters have interpreted these data 

elements in different ways. It appears 

that one common interpretation is to 

report the mole fraction for the 

emissions source type with the most 

flared emissions. Because that 

interpretation does not align with the 

EPA’s intent, clarification of this 

reporting requirement is needed to 

improve the verification process. Thus, 

we are proposing to modify these 

reporting elements, both in 40 CFR 

98.236(n) (proposed to be moved to 40 

CFR 98.236(n)(1)(ix) and (x)) and for all 

the proposed activity data reporting 

elements for individual source types 

that are subject to source-specific flared 

emissions reporting as described above. 

Specifically, we are proposing to require 

the flow-weighted annual average mole 

fraction of CH4 over all streams from a 

particular emission source type that are 

used in equation W–19 to calculate the 

reported flared CH4 emissions from that 

emission source type (and used in 

equation W–20 to calculate CO2

emissions). For example, if a flare 

receives gas from an acid gas removal 

vent and a blowdown vent stack, both 

of which are miscellaneous flared 

sources, then the CH4 mole fraction to 

report should be the flow-weighted 

annual average value from the acid gas 

removal vent and each blowdown 

through the blowdown vent stack. The 

CO2 mole fractions to report would also 

be a flow-weighted annual average 

determined in the same manner. 

Third, reporters are required to use 

equation W–40 to calculate N2O 

emissions from flares. Variables in the 

equation are the volume of gas routed to 

the flare and the HHV of the gas. The 

volume of gas routed to the flare must 

be reported, but the HHV is not 

reported. As a result, when reported 

N2O emissions differ significantly from 

the amount that would be expected if 

using the default HHV, it can be 

difficult for the EPA to determine 

whether the reported emissions are an 

error or if the difference is due to the 

use of a site-specific HHV. To improve 

the verification process and potentially 

reduce the amount of communication 

with reporters via e-GGRT, we are 

proposing to add a reporting element 

that would require reporters to indicate 

whether each reported N2O value is 

based on the default HHV, a site-specific 

HHV(s), or both the default and sitespecific HHVs. The proposed reporting 

element would be added in 40 CFR 

236(n)(4)(iv) for miscellaneous flared 

sources, and it would be included as 

one of the proposed activity data 

reporting elements for each of the other 

source types that are subject to sourcespecific flared emissions reporting. 

Providing an option to indicate that 

both types of HHVs are used is needed 

because some reported flared N2O 

emissions are aggregated values over all 

flares in a sub-basin or county (e.g., for 

atmospheric tanks), and a reporter may 

choose to use different methods for the 

flares in each sub-basin or county. In 

addition to improving the verification 

process, knowledge of site-specific 

HHVs would allow the EPA to assess 

how well the default HHV characterizes 

flared gas streams in different industry 

segments and basins. 

Fourth, an additional finding from the 

currently reported data is that a number 

of facilities in the Onshore Petroleum 

and Natural Gas Production industry 

segment, the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segment, and the Onshore 

Natural Gas Processing industry 

segment report significant amounts of 

emissions from miscellaneous flared 

sources. It is not clear what sources are 

generating the large amount of gas that 

is routed to these flares. To help clarify 

the source types that are generating 

large amounts of flared gas, we are 

proposing in 40 CFR 98.236(n)(1)(v) to 

require reporting by facilities in these 

three industry segments of an estimate 

of the fraction of the gas burned in the 

flare that is obtained from other 

facilities specifically for flaring as 

opposed to being generated in on-site 

operations. As an example, if an owner 

or operator has an onshore petroleum 

and natural gas production and an 

onshore petroleum and natural gas 

gathering and boosting facility in the 

same basin and routes associated gas 

from wells in the onshore petroleum 

and natural gas production facility to a 

flare that is defined as part of the 

onshore petroleum and natural gas 

gathering and boosting facility, then the 

flared emissions would be reported by 

the onshore petroleum and natural gas 

gathering and boosting facility as 

emissions from ‘‘other flare stacks’’ 

sources under the current rule (or from 

miscellaneous flared sources under the 

proposed amendments). If the other gas 

streams routed to the flare are from 

sources at the onshore petroleum and 

natural gas gathering and boosting 

facility, then for this proposed reporting 

requirement, the onshore petroleum and 

natural gas gathering and boosting 

facility report would include an 

estimate of the fraction of the total gas 

burned in the flare that is associated gas 

from the onshore petroleum and natural 

gas production facility. We request 

comment on the types of sources that 

may be generating these large emissions 

and whether other reporting elements 

could be specified that would better 

achieve the EPA’s objective of clearly 

characterizing the sources of flared 

emissions from facilities in the three 

industry segments identified above. For 

example, one potential additional 

reporting element could be a 

requirement to describe the primary 

source of miscellaneous flared 

emissions for any flare that reports CO2

emissions greater than an amount that 

would be determined if such a reporting 

requirement were finalized. 

Finally, one objective of the current 

flare reporting requirements is to obtain 

information on the total number of 

flares and their operating 

characteristics. If the proposed changes 

to flare activity data requirements as 

described previously in this section 

were finalized, then additional 

amendments to reporting requirements 

would be needed to continue collecting 

flare-specific information. Thus, we are 

proposing to require reporting of a list 

of all flare IDs per facility and add 

reporting for a series of flare-specific 

data elements. One of the proposed flare 

reporting elements is the total volume of 


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36972 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

gas routed to the flare. This information 

is consistent with current reporting 

requirements and would be helpful in 

conducting verification of other 

reported flare data because the sum of 

the total volume from all flares should 

be equal to the sum of the disaggregated 

volumes reported for all flared 

emissions source types. The total 

volumes per flare also would provide 

information on the range of flare sizes 

in different industry segments and 

would be useful in analyses for 

potential future policy decisions related 

to flares. Another of the proposed flare 

reporting elements is a list of the 

subpart W emission source types that 

routed emissions to the flare stack. This 

proposed data element would improve 

verification of other reported flare data 

as well as provide information regarding 

the types of sources that are combined 

and routed to the same flare. We are also 

proposing a few new flare-specific 

reporting elements to help us better 

understand the state of flaring in the 

industry, such as an indication of the 

type of the flare (e.g., open ground-level 

flare, enclosed ground-level flare, open 

elevated flare, or enclosed elevated 

flare) and the type of flare assist (e.g., 

unassisted, air-assisted (with indication 

of single-, dual-, or variable-speed fan), 

steam-assisted, or pressure-assisted). 

Further, researchers conducting remote 

sensing tests of emissions from flares 

have reported detecting much larger 

quantities of emissions from un-lit flares 

than is evident from the GHGRP data. 

To help us better understand the 

prevalence of emissions from un-lit 

flares, we are proposing to add 

requirements to report an indication of 

whether the flare has a continuous pilot 

or autoigniter, whether the presence of 

flame is continuously monitored if the 

flare has a continuous pilot, and an 

indication of how the reporter identifies 

periods when the flare is not lit if the 

flare does not have a continuous pilot. 

These proposed data elements would be 

added in 40 CFR 98.236(n). This 

paragraph of subpart W would be 

rearranged into two subparagraphs. The 

first subparagraph, 40 CFR 98.236(n)(1), 

would include the current activity data 

and emissions data reporting elements 

but would be revised to be specific to 

miscellaneous flared sources (as 

discussed previously), and the proposed 

flare-specific reporting elements would 

be added in the second subparagraph, 

40 CFR 98.236(n)(2). 

Definition of flare stack emissions. In 

response to a verification message in eGGRT, one reporter noted that the 

definition of the term ‘‘flare stack 

emissions’’ in 40 CFR 98.238 does not 

include CO2 that is in streams routed to 

the flare. The term is currently defined 

to mean ‘‘CO2 and N2O from partial 

combustion of hydrocarbon gas sent to 

a flare plus CH4 emissions resulting 

from the incomplete combustion of 

hydrocarbon gas in flares.’’ Based on 

this definition, the reporter concluded 

that CO2 in streams routed to the flare 

are not to be reported as flare stack 

emissions. However, the current 

definition, which was added to the 2010 

Final Revisions Rule after consideration 

of comments on the 2010 re-proposal, 

does not clearly convey the EPA’s intent 

that the CO2 that enters a flare should 

be reported as flare stack emissions. 

This intent is evident from the fact that 

equation W–20 includes a term for the 

inlet gas volume times the CO2 mole 

fraction in the inlet gas. Additionally, in 

a response to a comment on the 2010 

proposed rule, the EPA clearly stated 

that the total quantity of CO2, including 

both combusted CO2 (i.e., CO2 created in 

the flare) and uncombusted CO2 (i.e., 

CO2 that entered and simply passed 

through the flare), is to be calculated. 

Another issue with the current 

definition is that it implies N2O 

emissions only result from partial 

combustion of hydrocarbons in the gas 

routed to the flare. This is likely the 

primary mechanism for generating N2O 

emissions when combusting fuels that 

include nitrogen-containing 

compounds. However, natural gas and 

field gas have negligible amounts of 

fuel-bound nitrogen. For combustion of 

these fuels, it appears the N2O is 

generated primarily from converting 

thermal NOX under certain operating 

conditions in the flare. To eliminate the 

unintended inconsistency between the 

definition and the intent that CO2 in gas 

routed to the flare is to be reported as 

emissions from the flare, to clarify the 

requirement to calculate and report total 

CO2 that leaves the flare, and to clarify 

the source of flared N2O emissions, we 

are proposing to revise the definition of 

the term ‘‘flare stack emissions’’ to mean 

CO2 in gas routed to a flare, CO2 from 

partial combustion of hydrocarbons in 

gas routed to a flare, CH4 resulting from 

the incomplete combustion of 

hydrocarbons in gas routed to a flare, 

and N2O resulting from operation of a 

flare. 

Calculation methodology for flared 

emissions. In addition to proposing 

changes to the flare reporting 

requirements as discussed above, we are 

also proposing to clarify language in the 

emission calculation procedures of 40 

CFR 98.233(n) that we believe may be 

ambiguous for flares that do not have 

CEMS, consistent with section II.A.5 of 

this preamble. The procedures for 

determining the volume and 

composition of gas routed to flares for 

use in the emission calculation 

equations for a particular emission 

source type are currently specified in 

two places for each source type. Each 

source type-specific paragraph in 40 

CFR 98.233 specifies calculation 

methodologies for that emissions source 

type, as do 40 CFR 98.233(n)(1) and (2). 

The procedures in the source typespecific requirements specify only that 

the volume and composition of the 

flared gas are to be determined using the 

procedures for estimating vented 

emissions from that source type, but 

they also cross-reference the calculation 

method in 40 CFR 98.233(n) for 

determining the emissions from the 

flaring of that gas stream. However, 40 

CFR 98.233(n)(1) and (2) specify that if 

continuous flow or composition 

measurement devices are used on the 

gas to the flare, then data from those 

devices must be used to calculate 

emissions; otherwise, estimates may be 

used. The intent is that the procedures 

in 40 CFR 98.233(n) should take 

precedence, but this may not be clear to 

all reporters. Additionally, the 

procedures for continuous measurement 

devices in 40 CFR 98.233(n)(1) and (2) 

refer to devices ‘‘on the flare’’ or ‘‘on gas 

to the flare.’’ The intent is that the 

procedures should apply to devices 

regardless of whether they are on a 

stream routed from a single emission 

source or on a stream routed to a flare 

that includes streams combined from 

multiple emission source types, but this 

is not explicitly described. A third 

potential ambiguity is that procedures 

in 40 CFR 98.233(n)(1) and (2) do not 

specify how to disaggregate data 

collected with a continuous 

measurement device when the device 

measures a combined stream from more 

than one emission source type. 

To clarify these requirements, we are 

proposing to specify all of the potential 

options for determining volume and 

composition of gas to the flare(s) in the 

applicable sections of 40 CFR 98.233 for 

each of the emission source types that 

have flared emissions reporting 

requirements. In general, the volume of 

gas would be determined by a 

continuous flow measurement device, if 

available, or using the methods for 

determining vented emissions for the 

applicable emission source type. If the 

measured volume includes flow from 

multiple source types routed to the 

same flare, reporters would use process 

knowledge and best available data to 

determine the portion of the total flow 


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77The proposed revisions to 40 CFR 98.233(n)(1) 

would remove ‘‘company records’’ from the existing 

list of information upon which engineering 

calculations may be based. In this instance, the use 

of ‘‘company records’’ was intended to refer 

generally to facility records rather than the specific 

type of records as defined in 40 CFR 98.3, and we 

expect that general facility records are covered by 

the proposed inclusion of process knowledge and 

best available data. Therefore, we are proposing to 

remove the defined term ‘‘company records’’ solely 

to avoid confusion for reporters; this amendment is 

not intended to indicate a change in the engineering 

calculations. 

from each emission source type.77

Similarly, the composition of the gas 

from the emission source type would be 

determined by a continuous 

composition analyzer, if available, or 

using the methods for determining the 

composition of the vented emissions for 

the applicable emission source type. 

Alternatively, if multiple source types 

are routed to one flare and the gas 

routed to the flare from each of those 

source types is expected to have similar 

compositions, the reporter could 

measure the composition of the total gas 

to the flare using a continuous 

composition analyzer just upstream of 

the flare and apply the results to each 

of the applicable source types. The 

source-specific sections of 40 CFR 

98.233 would then cross-reference only 

40 CFR 98.233(n)(3) through (8) for the 

applicable calculation equations and 

procedures for determining combustion 

efficiency, converting volumetric 

emissions to mass emissions, and the 

separate procedures that apply if a 

CEMS is used on gases from the flare. 

As part of this proposed amendment, we 

would also remove 40 CFR 98.233(n)(9); 

with these proposed calculation 

methodology clarifications and the 

reporting clarifications described earlier 

in this section, a general direction to 

correct flare emissions to avoid double 

counting would no longer be necessary 

(however, a provision specifically to 

avoid double counting of CO2 emissions 

from acid gas removal units that route 

emissions to a flare would still be 

needed, as discussed later in this 

section). We recognize that the proposed 

changes introduce some repetition to 

the regulatory text overall because the 

requirements for each emission source 

type are similar. However, clearly 

describing the applicable procedures for 

each source type separately rather than 

trying to generally describe a single set 

of consolidated procedures would make 

the rule easier for reporters to 

understand, and we request comment 

on whether the proposed changes 

achieve this goal. 

Calculation methodologies for flared 

emissions from acid gas removal vents. 

We are also proposing source typespecific provisions for calculating and 

reporting emissions from acid gas 

removal vents routed to flares that are 

related to the proposed calculation 

methodology clarifications described 

earlier in this section, consistent with 

section II.A.5 of this preamble. 

Reporters are currently required to 

report the CO2 removed from the natural 

gas as CO2 emissions from acid gas 

removal vents, and that quantity is not 

affected (i.e., the CO2 is not converted to 

another compound) when the acid gas 

vent stream is routed to a flare, engine, 

or sulfur recovery plant. Therefore, the 

current rule does not require reporters 

to separate emissions vented directly to 

the atmosphere from emissions routed 

through a flare, engine, or sulfur 

recovery plant. Instead, as noted earlier 

in this section, 40 CFR 98.233(n)(9) 

specifies that the total CO2 for a flare 

that receives gas from acid gas removal 

vents must be adjusted downward by 

the amount of the CO2 emissions that 

are calculated for those acid gas removal 

vents. In other words, the CO2 emissions 

that are calculated for the acid gas 

removal vents are reported under 40 

CFR 98.236(d) and not under 40 CFR 

98.236(n). 

Because the reporting of emissions 

from acid gas removal vents routed to a 

flare is addressed differently in the 

current rule from the reporting of flared 

emissions for all other source types, we 

are proposing amendments for acid gas 

removal vents routed to flares that are 

slightly different than the proposed 

amendments for other sources. First, as 

noted previously in this section, we are 

proposing to remove 40 CFR 

98.233(n)(9) because it would be 

unnecessary for other source types in 

light of the other amendments 

previously described. However, for acid 

gas removal vents routed to flares, an 

adjustment would still be necessary for 

CO2 emissions. Therefore, we are 

proposing to add provisions in 40 CFR 

98.233(d)(12) for calculating emissions 

from acid gas removal vents routed to 

flares (as described in more detail in the 

next paragraph) and proposing to add a 

clarification to the requirement to report 

CO2 emissions from flare stacks (40 CFR 

98.236(n)(9), proposed to be moved to 

40 CFR 98.236(n)(1)(xi)) indicating that 

the reported CO2 emissions should not 

include emissions from acid gas 

removal vents reported under 40 CFR 

98.236(d)(1)(v) to prevent double 

counting of emissions. 

Second, we reviewed the calculation 

methods for acid gas removal vents and 

flares, and we are proposing 

amendments to more closely align the 

methods for acid gas removal vents 

routed to flares. For acid gas removal 

vents, Calculation Method 1 (40 CFR 

98.233(d)(1)) is required to be used if a 

vent has a CEMS installed, and 

Calculation Method 2 (40 CFR 

98.233(d)(2)) is required to be used if a 

vent has a continuous flow monitor. If 

there is no CEMS or flow monitor 

installed, then reporters currently must 

use Calculation Methods 3 or 4 (40 CFR 

98.233(d)(3) or (4), which are estimation 

methods based on the volume of natural 

gas treated and the acid gas contents of 

the inlet and outlet natural gas. 

However, because these are estimation 

methods rather than methods based on 

measurements, the EPA has found 

through the verification process and 

correspondence with reporters via eGGRT that these methods can 

sometimes result in estimated 

volumetric CO2 emissions from acid gas 

removal vents routed to a flare that are 

greater than the reported total volume of 

gas routed to that flare. Therefore, we 

are proposing new provisions in 40 CFR 

98.233(d)(12) for reporters routing acid 

gas removal vents to flares. The first set 

of amendments would apply to acid gas 

removal vents that are routed to any 

dedicated flare as well as acid gas 

removal vents comingled with 

emissions from other source types and 

routed to flares with no continuous 

monitors for either the flow or 

composition of the comingled gas 

stream. In either of these cases, reporters 

would continue to calculate CO2

emissions using one of the Calculation 

Methods 1 through 4, as applicable for 

the type of monitoring available, and 

would continue to report those 

emissions under 40 CFR 98.236(d) 

rather than 40 CFR 98.236(n). Reporters 

would also incorporate the flow rate and 

composition of the acid gas removal 

vent stream into the calculation of total 

flare emissions from miscellaneous 

flared sources. For acid gas removal 

vent streams comingled with emissions 

from other source types and routed to 

flares with continuous monitoring of the 

flow and/or composition of the 

comingled gas stream, we are proposing 

that reporters would first determine the 

total emissions from the flare stacks and 

then use site-specific engineering 

estimates based on best available data to 

estimate the portion of the total flared 

CO2 emissions that is from the acid gas 

removal vents. In this case, we are 

proposing that reporters would select 

‘‘Routed to a flare [§ 98.233(d)(12)(ii)]’’ 

as the calculation method. We are also 

proposing new reporting requirements 

for acid gas removal vents routed to 

flares; in addition to the current 

requirements to report the CO2

emissions under 40 CFR 98.236(d)(1)(v), 


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36974 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

78Currently, subpart W does not require 

measurements for centrifugal compressors in 

standby-pressurized-mode and therefore does not 

define this mode for centrifugal compressors. 

79Subramanian, R. et al. ‘‘Methane Emissions 

from Natural Gas Compressor Stations in the 

Transmission and Storage Sector: Measurements 

and Comparisons with the EPA Greenhouse Gas 

Reporting Program Protocol.’’ Environ. Sci. Technol. 

49, 3252–3261. 2015. Available in the docket for 

this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

we are proposing to add the 

identification of the flare to which the 

acid gas removal vent is routed. 

j. Compressors 

Compressors are used across the 

petroleum and natural gas industry to 

raise the pressure of and convey natural 

gas or CO2. The two main types of 

compressors used in the industry are 

centrifugal compressors and 

reciprocating compressors. Subpart W 

requires Onshore Petroleum and Natural 

Gas Production and Onshore Petroleum 

and Natural Gas Gathering and Boosting 

facilities to calculate compressor 

emissions using population emission 

factors. Population emission factors are 

multiplied by the count of equipment, 

in this case compressors of a certain 

type, to calculate emissions. For the 

Onshore Natural Gas Processing, 

Onshore Natural Gas Transmission 

Compression, Underground Natural Gas 

Storage, LNG Storage, and LNG Import 

and Export Equipment industry 

segments, subpart W requires facilities 

to annually measure the emissions from 

the compressor sources applicable to the 

mode the compressor is in at the time 

of the measurement; facilities also have 

the option to continuously measure 

emissions from a compressor source. 

The annual measurements are called ‘‘as 

found’’ measurements because the 

compressors are to be measured in the 

mode in which they are found when the 

measurements are made. The ‘‘as 

found’’ measurements are required for 

each centrifugal and reciprocating 

compressor at least annually, but only 

for those compressor emission sources 

that have measurement requirements for 

the mode in which they are found (i.e., 

the defined ‘‘compressor mode-source 

combinations’’), as described in the 

following paragraph. 

Subpart W defines the following 

‘‘compressor sources’’: wet seal 

degassing vent (for centrifugal 

compressors only); rod packing 

emissions (for reciprocating 

compressors only); blowdown valve 

leakage through the blowdown vent (for 

both centrifugal and reciprocating 

compressors) and unit isolation valve 

leakage through the open blowdown 

vent without blind flanges (for both 

centrifugal and reciprocating 

compressors). Subpart W also defines 

the following ‘‘compressor modes’’: 

operating-mode (for both centrifugal and 

reciprocating compressors), standbypressurized-mode (for reciprocating 

compressors only 78), and not-operatingdepressurized-mode (for both 

centrifugal and reciprocating 

compressors). Some compressor sources 

may only release emissions during 

certain compressor modes. Therefore, 

subpart W uses the term ‘‘compressor 

mode-source combination’’ to refer to 

the specific compressor sources that 

must be measured based on the mode in 

which the compressor is found. 

For centrifugal compressors, subpart 

W requires measurement in the 

following compressor mode-source 

combinations: wet seal oil degassing 

vents in operating-mode, blowdown 

valve leakage through the blowdown 

vent in operating-mode, and unit 

isolation valve leakage through an open 

blowdown vent without blind flanges in 

not-operating-depressurized-mode. For 

reciprocating compressors, subpart W 

requires measurement in the following 

compressor mode-source combinations: 

rod packing emissions in operatingmode, blowdown valve leakage through 

the blowdown vent in operating-mode, 

blowdown valve leakage through the 

blowdown vent in standby-pressurizedmode, and unit isolation valve leakage 

through an open blowdown vent 

without blind flanges in not-operatingdepressurized-mode. 

The EPA is proposing several 

amendments related to the ‘‘as found’’ 

measurement requirements to improve 

the quality of data collected for 

compressors. First, standby-pressurizedmode was not included as a mode for 

centrifugal compressors in the subpart 

W definition of ‘‘compressor mode’’ and 

no compressor mode-source 

combinations were defined for 

centrifugal compressors in standbypressurized-mode. While centrifugal 

compressors are seldom in the standbypressurized-mode, there have been 

several occasions when reporters have 

indicated through the GHGRP Help 

Desk that a centrifugal compressor was 

in this mode during the ‘‘as found’’ 

measurement. This has led to confusion 

from reporters regarding how to report 

the data from the measurements 

performed. To address this issue, we are 

proposing to add standby-pressurizedmode to the defined modes for 

centrifugal compressors (40 CFR 98.238) 

and require measurement of volumetric 

emissions from the wet seal oil 

degassing vent and volumetric 

emissions from blowdown valve leakage 

through the blowdown vent when the 

compressor is found in this mode (40 

CFR 98.233(o)(1)(i)(C) as proposed), 

consistent with sections II.A.2 and 

II.A.5 of this preamble. 

Second, dry seals on centrifugal 

compressors were not included in the 

subpart W definition of ‘‘compressor 

source’’ and no compressor modesource combinations were defined for 

dry seals on centrifugal compressors. 

While emissions from wet seal oil 

degassing vents are expected to be larger 

than from dry seals, dry seals may still 

contribute to centrifugal compressor 

emissions. Additionally, the 

measurement crew will already be at the 

centrifugal compressor to make the ‘‘as 

found’’ measurement for blowdown 

valve leakage. Therefore, to better 

characterize the emissions from dry seal 

centrifugal compressors, we are 

proposing to add dry seal vents to the 

defined compressor sources for 

centrifugal compressors (40 CFR 98.238) 

and require measurement of volumetric 

emissions from the dry seal vents in 

both operating-mode and in standbypressurized-mode (40 CFR 

98.233(o)(2)(iii) as proposed), consistent 

with section II.A.2 of this preamble. 

Proposed measurement methods for the 

dry seal vents are similar to those 

provided for reciprocating compressor 

rod packing emissions and would 

include the use of temporary or 

permanent flow meters, calibrated bags, 

and high volume samplers. Screening 

methods may also be used to determine 

if a quantitative measurement is 

required. Acoustical screening or 

measurement methods are not 

applicable to dry seal vents because 

these emissions are not a result of 

through-valve leakage. These proposed 

revisions include a proposed new 

reporting requirement to report the 

number of dry seals on centrifugal 

compressors and the reporting of 

emission measurements made on the 

dry seals. 

Third, we are proposing to revise 40 

CFR 98.233(p)(1)(i) to require 

measurement of rod packing emissions 

for reciprocating compressors when 

found in the standby-pressurized-mode 

because recent studies indicate that rod 

packing emissions can occur while the 

compressor is in this mode.79 The 

inclusion of this compressor modesource combination would more 

accurately reflect compressor emissions, 

consistent with section II.A.2 of this 

preamble. Furthermore, the 

measurement crew will already be at the 

compressor to make the ‘‘as found’’ 


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measurement for blowdown valve 

leakage and several reporters already 

make these measurements. 

Fourth, we are proposing to revise the 

allowable methods for measuring wet 

seal oil degassing vents. Since the 

inception of subpart W, the only method 

provided in 40 CFR 98.233(o)(2)(ii) for 

measuring volumetric flow from wet 

seal oil degassing vents has been the use 

of a temporary or permanent flow meter. 

The limitation in methods allowed for 

wet seal oil degassing vents was due to 

the expectation that the volumetric 

flows may exceed the quantitative limits 

of these other methods. In reviewing the 

data reported for the wet seal oil 

degassing vent, we found that the 

measured flow rates using flow meters 

are often within the limits of other 

measurement methods allowed for other 

compressor sources. We also found that 

many reporters have overlooked the 

restriction on the methods allowed for 

wet seal oil degassing vents and often 

reported using other measurement 

methods (e.g., high volume samplers). 

We have found that most of these 

measured flow rates appear to be within 

the capacity limits of a typical high 

volume sampler. In the small minority 

of cases in which flow rates would be 

outside of the capacity limit of the 

instrument, facilities can use an 

alternate method, consistent with the 

requirements for other compressor 

source measurements. Consequently, we 

concluded that the measurement 

methods allowed for wet seal oil 

degassing vents could be expanded to 

include the use of calibrated bags and 

high volume samplers. Therefore, we 

are proposing to revise 40 CFR 

98.233(o)(2)(ii) to allow the use of 

calibrated bags and high volume 

samplers. However, we are not 

proposing to allow the use of screening 

methods because wet seal oil degassing 

vents are expected to always have some 

natural gas flow. Therefore, we are 

proposing to retain and clarify this 

unique limitation on the use of 

screening methods for wet seal oil 

degassing vent measurement methods. 

This proposed revision would provide 

greater flexibility and improved clarity 

of the wet seal oil degassing provisions 

consistent with section II.A.2 of this 

preamble. 

Fifth, we are proposing to remove 

acoustic leak detection from the 

screening and measurement methods 

allowed for manifolded groups of 

compressor sources. As noted in 40 CFR 

98.234(a)(5), acoustic leak detection is 

applicable only for through-valve 

leakage. The acoustic method can be 

applied to individual compressor 

sources associated with through-valve 

leakage (i.e., blowdown valve leakage or 

isolation valve leakage), but it cannot be 

applied to a vent that contains a group 

of manifolded compressor sources 

downstream from the individual valves 

or other sources that may be manifolded 

together. The inclusion of this method 

for manifolded compressor sources was 

in error and we are proposing to remove 

it from 40 CFR 98.233(o)(4)(ii)(D) and 

(E) and 40 CFR 98.233(p)(4)(ii)(D) and 

(E) to improve accuracy of the 

measurements, consistent with section 

II.A.2 of this preamble. 

Sixth, we are proposing a number of 

clarifications to the references to the 

allowed measurement methods to 

correct errors and improve the clarity of 

the rule, consistent with section II.A.5 

of this preamble. These proposed 

revisions include: revising 40 CFR 

98.233(o)(1)(i)(A) and (B) to reference 40 

CFR 98.233(o)(2)(i) instead of specific 

subparagraphs of that paragraph that 

may be construed to limit the methods 

allowed for blowdown or isolation valve 

leakage measurements; revising 40 CFR 

98.233(p)(1)(i)(A), (B) and (C) to 

reference 40 CFR 98.233(p)(2)(i) instead 

of specific subparagraphs of that 

paragraph that may be construed to 

limit the methods allowed for 

blowdown or isolation valve leakage 

measurements; revising 40 CFR 

98.233(p)(1)(i)(A) and (C) (as proposed) 

to reference ‘‘paragraph (p)(2)(ii) or (iii) 

of this section as applicable’’ instead of 

only ‘‘paragraph (p)(2)(ii)’’ to clarify that 

measurement of rod packing emissions 

without an open-ended vent line are to 

be made according to 40 CFR 

98.233(p)(2)(iii); and revising 40 CFR 

98.233(p)(2)(ii)(C) and (iii)(A) to clarify 

that acoustic leak detection is not an 

applicable screening method for rod 

packing emissions (not a through-valve 

leakage). 

In addition to these proposed 

revisions to the ‘‘as found’’ 

measurement requirements, we are also 

proposing to clarify the language at 40 

CFR 98.233(o)(10) and (p)(10) for 

compressors at Onshore Petroleum and 

Natural Gas Production or Onshore 

Petroleum and Natural Gas Gathering 

and Boosting facilities, consistent with 

section II.A.2 of this preamble. The 

compressor emission factors for these 

industry segments are specific to 

uncontrolled wet seal oil degassing 

vents on centrifugal compressors and 

uncontrolled rod packing emissions for 

reciprocating compressors. The 

language in 40 CFR 98.233(o) and (p) 

clearly indicates that the provisions of 

40 CFR 98.233(o)(10) and (p)(10) do not 

apply for controlled compressor 

sources. However, proposed revisions 

are necessary to provide clarity 

regarding the compressor sources for 

which emissions are required to be 

calculated under 40 CFR 98.233(o)(10) 

and (p)(10) and reported under 40 CFR 

98.236(o)(5) and (p)(5). Specifically, we 

are proposing minor revisions to 40 CFR 

98.233(o)(10) and the corresponding 

reporting requirements in 40 CFR 

98.236(o)(5) to clarify that the 

compressor count used in equation W– 

25 should be the number of centrifugal 

compressors with atmospheric (i.e., 

uncontrolled) wet seal oil degassing 

vents. Similarly, we are proposing 

minor revisions to 40 CFR 98.233(p)(10) 

and the corresponding reporting 

requirements in 40 CFR 98.236(p)(5) to 

clarify that the compressor count used 

in equation W–29D should be the 

number of reciprocating compressors 

with atmospheric (i.e., uncontrolled) 

rod packing emissions. Finally, we are 

proposing to add requirements to report 

the total number of centrifugal 

compressors at the facility and the 

number of centrifugal compressors that 

have wet seals to 40 CFR 98.236(o)(5) 

and proposing to add a requirement to 

report the total number of reciprocating 

compressors at the facility to 40 CFR 

98.236(p)(5). These additional data 

would provide the EPA with an 

improved understanding of the total 

number of compressors and the number 

of compressors that are controlled (i.e., 

routed to flares, combustion, or vapor 

recovery systems) in the Onshore 

Petroleum and Natural Gas Production 

and Onshore Petroleum and Natural Gas 

Gathering and Boosting industry 

segments, consistent with section II.A.4 

of this preamble. 

k. Equipment Leak Surveys 

Addition of leaker emission factors for 

survey methods other than method 21. 

Subpart W reporters are required to 

quantify emissions from equipment 

leaks using the calculation methods in 

40 CFR 98.233(q) (equipment leak 

surveys) and/or 40 CFR 98.233(r) 

(equipment leaks by population count). 

The equipment leak survey method uses 

the count of leakers detected with one 

of the subpart W leak detection methods 

in 40 CFR 98.234(a), subpart W leaker 

emission factors, and operating time to 

estimate the emissions from equipment 

leaks. The current leaker emission 

factors applicable to onshore petroleum 

and natural gas production and onshore 

petroleum and natural gas gathering and 

boosting facilities are found in Table W– 

1E of subpart W. These leaker emission 

factors are based on the EPA’s Protocol 

for Equipment Leak Emission Estimates 

published in 1995 (Docket Id. No. EPA– 

HQ–OAR–2009–0927–0043), also 

available in the docket for this 


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80See, e.g., ERG (Eastern Research Group, Inc.) 

and Sage (Sage Environmental Consulting, LP). City 

of Fort Worth Natural Gas Air Quality Study: Final 

Report. July 13, 2011, available at https://

www.fortworthtexas.gov/departments/developmentservices/gaswells/air-quality-study/final; Allen, 

D.T., et al. ‘‘Measurements of methane emissions at 

natural gas production sites in the United States.’’ 

Proceedings of the National Academy of Sciences 

of the United States of America, Vol. 110, no. 44. 

pp. 17768–17773, October 29, 2013, available at 

http://dept.ceer.utexas.edu/methane/study. Docket 

Item No. EPA–HQ–OAR–2014–0831–0006; Pacsi, 

A.P., et al. ‘‘Equipment leak detection and 

quantification at 67 oil and gas sites in the Western 

United States.’’ Elem Sci Anth, 7: 29, available at 

https://doi.org/10.1525/elementa.368. 2019; 

Zimmerle, D., et al. ‘‘Methane Emissions from 

Gathering Compressor stations in the U.S.’’ 

Environmental Science & Technology 2020, 54(12), 

7552–7561, available at https://doi.org/10.1021/ 

acs.est.0c00516. The documents are also available 

in the docket for this rulemaking, Docket Id. No. 

EPA–HQ–OAR–2019–0424. 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. The leaker emission 

factors are provided for components in 

gas service, light crude service, and 

heavy crude service that are found to be 

leaking via several different screening 

methods. In addition to being 

component- and service-specific, 

subpart W currently provides two 

different sets of leaker emission factors: 

one based on leak rates for leaks 

identified by Method 21 (see 40 CFR 

part 60, appendix A–7) using a leak 

definition of 10,000 ppm and one based 

on leak rates for leaks identified by 

Method 21 using a leak definition of 500 

ppm. Currently, the other leak screening 

methods provided in subpart W (OGI, 

infrared laser beam illuminated 

instrument, and acoustic leak detection 

device) use the leaker emission factors 

based on Method 21 data with a leak 

definition of 10,000 ppm. 

In the years that have followed the 

adoption of these emission factors into 

subpart W, there have been numerous 

studies regarding emissions from 

equipment leaks that provide 

measurement data to quantify leaker 

emission factors for OGI screening 

methods at onshore petroleum and 

natural gas production and onshore 

petroleum and natural gas gathering and 

boosting facilities.80 These studies 

found that OGI identifies fewer yet 

larger leaks than the EPA’s Method 21. 

Specifically, the average leaker emission 

factor determined from OGI leak 

detection surveys is often a factor of two 

or more larger than leaker emission 

factors determined when using Method 

21 leak detection surveys. Therefore, the 

application of the same leaker emission 

factor to leaking components detected 

with OGI and Method 21 with a leak 

definition of 10,000 ppm, as is currently 

done in subpart W, likely understates 

the emissions from leakers detected 

with OGI. 

Based on our review of these studies, 

we are proposing to amend the leaker 

emission factors in Table W–1E for 

onshore petroleum and natural gas 

production and onshore petroleum and 

natural gas gathering and boosting 

facilities to include separate emission 

factors for leakers detected with OGI, 

consistent with section II.A.1 of this 

preamble. These emission factors were 

developed by combining the data from 

Zimmerle et al. (2020) and Pacsi et al. 

(2019) to provide OGI leaker emission 

factors by site type (i.e., gas or oil). 

These studies were selected as the basis 

for the proposed OGI emission factors 

because they included recent 

measurements of subpart W-specified 

equipment leak components from both 

oil and gas production and gathering 

and boosting sites in geographically 

diverse locations. The precise derivation 

of the proposed emission factors is 

discussed in more detail in the subpart 

W TSD, available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. 

At onshore petroleum and natural gas 

production and onshore petroleum and 

natural gas gathering and boosting 

facilities, very few facilities use infrared 

laser beam illuminated instruments or 

acoustic leak detection devices to 

conduct equipment leak surveys and 

there are no data available to develop 

leaker emission factors specific to these 

methods. Based on our understanding of 

these alternative methods, we expect 

that their leak detection thresholds 

would be most similar to OGI, so that 

the average emissions per leak 

identified by these alternative methods 

would be similar to the emissions 

estimated using the proposed OGI leaker 

factors. Therefore, we are proposing 

that, if these alternative methods are 

used to conduct leak surveys, the 

proposed OGI leaker emission factors 

would be used to quantify the emissions 

from the leaks identified using these 

other monitoring methods. 

For onshore petroleum and natural 

gas gathering and boosting facilities, all 

components are considered to be in gas 

service consistent with the language in 

40 CFR 98.233(q)(2)(iv); thus, the gas 

service factors from Table W–1E should 

be applied to all leakers. In order to 

make clear how onshore petroleum and 

natural gas production facilities should 

apply these revised emission factors, we 

are proposing to amend 40 CFR 

98.233(q)(2)(iii) to state that onshore 

petroleum and natural gas production 

facilities must use the appropriate 

default whole gas leaker emission 

factors consistent with the well type, 

where components associated with gas 

wells are considered to be in gas service 

and components associated with oil 

wells are considered to be in oil service 

as listed in Table W–1E to this subpart. 

As described previously, our analysis 

of measurement study data from 

onshore production and gathering and 

boosting facilities demonstrates that the 

OGI screening method finds fewer and 

larger leaks than Method 21. 

Consequently, the leaker emission 

factors derived using measurement data 

from the OGI screening method are 

larger than those derived using the 

measurement data from Method 21 

screening method. We expect that the 

leaker emission factors for other 

industry segments that are based on 

measurements of Method 21-identified 

leaks may similarly underestimate the 

emissions from leaking equipment when 

OGI (or other alternative methods 

besides Method 21) are used to detect 

the leaks. Therefore, we are proposing to 

apply the ‘‘OGI enhancement’’ factor 

identified from measurement study data 

in the onshore production and gathering 

and boosting industry segments to the 

leaker emission factors for the other 

subpart W industry segments as a means 

to estimate an OGI emission factor set. 

Analogous to the proposed changes in 

Table W–1E for the Onshore Petroleum 

and Natural Gas Production and 

Onshore Petroleum and Natural Gas 

Gathering and Boosting industry 

segments, this results in the addition of 

an emission factor set specific to OGI, 

infrared laser beam illuminated 

instrument, or acoustic leak detection 

device screening methods. The 

proposed emission factor sets are 

included in Tables W–2A, W–3A, W– 

4A, W–5A, W–6A, and W–7 for the 

Onshore Natural Gas Processing, 

Onshore Natural Gas Transmission 

Compression, Underground Natural Gas 

Storage, LNG Storage, LNG Import and 

Export Equipment, and Natural Gas 

Distribution industry segments, 

respectively. A detailed description of 

the proposed emission factors is 

discussed in more detail in the subpart 

W TSD, available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. 

As an alternative to the proposed 

revised default leaker emission factors, 

we are also proposing an option that 

would allow reporters to quantify 

emissions from equipment leak 

components in 40 CFR 98.233(q) by 

performing direct measurement of 

equipment leaks and calculating 

emissions using those measurement 

results, consistent with section II.A.2 of 

this preamble. The proposed 

amendments would provide that 


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Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 36977 

facilities with components subject to 40 

CFR 98.233(q) can elect to perform 

direct measurement of leaks using one 

of the subpart W measurement methods 

in 40 CFR 98.234(b) through (d) such as 

calibrated bagging or a high volume 

sampler. To use this proposed option, 

all leaks identified during a ‘‘complete 

leak detection survey’’ must be 

quantified; in other words, reporters 

could not use leaker emission factors for 

some leaks and quantify other leaks 

identified during the same leak 

detection survey. For the Onshore 

Petroleum and Natural Gas Production 

industry segment, a complete leak 

detection survey would be the fugitive 

emissions monitoring of a well site 

conducted to comply with NSPS 

OOOOa, NSPS OOOOb, or the 

applicable EPA-approved state plan or 

the applicable Federal plan in 40 CFR 

part 62 or, if the reporter elected to 

conduct the leak detection survey, a 

complete survey of all equipment on a 

single well-pad. For the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting industry segment, a 

complete leak detection survey would 

be the fugitive emissions monitoring of 

a compressor station to comply with 

NSPS OOOOa, NSPS OOOOb, or the 

applicable EPA-approved state plan or 

the applicable Federal plan in 40 CFR 

part 62 or, if the reporter elected to 

conduct the leak detection survey, a 

complete survey of all equipment at a 

gathering ‘‘compressor station’’ or at a 

‘‘centralized oil production site’’ (and 

we are proposing to define these terms 

in 40 CFR 98.238, as described in 

section III.J.1.p of this preamble). For 

downstream industry segments (e.g., 

Onshore Natural Gas Transmission 

Compression), a complete leak detection 

survey is facility-wide, and therefore, 

the election to perform direct 

measurement of leaks would also be 

facility-wide. In other words, this option 

would allow the use of measurement 

data directly when all leaks identified 

are quantitatively measured. 

The proposed amendments rely 

specifically on quantitative 

measurement methods already provided 

in the rule. We are seeking comment on 

alternative methods for quantifying 

leaks for use for these equipment leak 

measurements (and for ‘‘as found’’ 

compressor measurements) along with 

supporting information and data. The 

supporting information should include 

description of the method, limitations 

on the applicability of the method, and 

calibration requirements. Supporting 

data should include accuracy 

assessments relative to other 

quantitative measurement methods 

provided in the rule. 

Finally, as part of this overall 

amendment, we are also proposing to 

remove the additional Method 21 

screening when a survey is conducted 

using a method other than Method 21. 

Currently, facilities using survey 

methods other than Method 21 to detect 

equipment leaks may then screen the 

equipment identified as leaking using 

Method 21 to determine if the leak 

measures greater than 10,000 parts per 

million by volume (ppmv) (see, e.g., 40 

CFR 98.234(a)(1)). If the Method 21 

screening of the leaking equipment is 

less than 10,000 ppmv, then reporters 

may consider that equipment as not 

leaking. In the 2016 subpart W 

revisions, we added a leak detection 

methodology at 40 CFR 98.234(a)(6) 

(proposed to be moved to 40 CFR 

98.234(a)(1)(ii)) for using OGI in 

accordance with NSPS OOOOa, which 

does not include an option for 

additional Method 21 screening. As 

noted in response to comments on the 

subpart W proposal regarding the 

absence of this optional additional 

Method 21 screening when using OGI in 

accordance with NSPS OOOOa, the 

additional screening of OGI-identified 

leaking equipment using Method 21 

requires additional effort from reporters 

(81 FR 86500, November 30, 2016). 

Furthermore, as noted previously in this 

section, the average emissions of leakers 

identified by OGI are greater than leaks 

identified by Method 21. Directly 

applying the number of OGI-identified 

leaks to the subpart W leaker emission 

factor specific to that survey method 

would provide the most accurate 

estimate of emissions, while selectively 

screening OGI-identified leaks using 

Method 21 to reduce the number of 

reportable leakers would yield a low 

bias in the reported emissions. 

Therefore, we are proposing to require 

reporters to directly use the leak survey 

results for the monitoring method used 

to conduct the complete leak survey and 

are proposing to eliminate this 

additional Method 21 screening 

provision. In addition to providing more 

accurate emissions data consistent with 

section II.A.2 of this preamble, the 

removal of the additional monitoring 

step would streamline and improve 

implementation consistent with section 

II.B.2 of this preamble. 

Amendments related to oil and 

natural gas standards and emissions 

guidelines in 40 CFR part 60. As noted 

in the introduction to section III.J of this 

preamble, the EPA recently proposed 

NSPS OOOOb and EG OOOOc for oil 

and natural gas new and existing 

affected sources, respectively. Under the 

proposed standards in NSPS OOOOb 

and the proposed presumptive 

standards in EG OOOOc, owners and 

operators would be required to 

implement a fugitive emissions 

monitoring and repair program for the 

collection of fugitive emissions 

components at well site and compressor 

station affected sources. In addition, the 

proposed NSPS OOOOb and EG OOOOc 

include a proposed appendix K to 40 

CFR part 60, an OGI-based method for 

detecting leaks and fugitive emissions 

from all components that is not 

currently provided in subpart W. The 

EPA also proposed provisions in NSPS 

OOOOb and EG OOOOc for equipment 

leak detection and repair at onshore 

natural gas processing facilities. Similar 

to the 2016 amendments to subpart W 

(81 FR 4987, January 29, 2016), the EPA 

is proposing to revise the calculation 

methodology for equipment leaks in 

subpart W so that data derived from 

equipment leak and fugitive emissions 

monitoring conducted under NSPS 

OOOOb or the applicable approved state 

plan or applicable Federal plan in 40 

CFR part 62 would be used to calculate 

emissions, consistent with section II.A.2 

of this preamble. 

First, under these proposed 

amendments, facilities with certain 

fugitive emissions components at a well 

site or compressor station subject to 

NSPS OOOOb or an applicable 

approved state plan or applicable 

Federal plan in 40 CFR part 62 would 

use the data derived from the NSPS 

OOOOb or 40 CFR part 62 fugitive 

emissions requirements along with the 

subpart W equipment leak survey 

calculation methodology and leaker 

emission factors to calculate and report 

their GHG emissions to the GHGRP. 

Specifically, the proposed amendments 

would expand the cross-reference to 40 

CFR 60.5397a to include the analogous 

requirements in NSPS OOOOb or 40 

CFR part 62. Facilities with fugitive 

emissions components not subject to the 

standards in the proposed NSPS 

OOOOb or addressed by the 

presumptive standards in the proposed 

EG OOOOc and subject to 40 CFR part 

62 would continue to be able to elect to 

calculate subpart W equipment leak 

emissions using the leak survey 

calculation methodology and leaker 

emission factors (as is currently 

provided in 40 CFR 98.233(q)). 

Therefore, reporters with other fugitive 

emission sources at subpart W facilities 

not covered by NSPS OOOOb or 40 CFR 

part 62 (e.g., sources subject to other 

state regulations and sources 

participating in the Methane Challenge 

Program or other voluntarily 


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36978 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

81We are similarly proposing to revise the 

existing reporting requirement related to NSPS 

OOOOa, such that reporters would report whether 

any of the surveys of well sites or compressor 

stations used in calculating emissions under 40 CFR 

98.233(q) were conducted to comply with the 

fugitive emissions standards in NSPS OOOOa 

(rather than simply reporting whether the facility 

has well sites or compressor stations subject to the 

fugitive emissions standards in NSPS OOOOa). 

implemented programs) would continue 

to have the opportunity to voluntarily 

use the proposed leak detection 

methods to calculate and report their 

GHG emissions to the GHGRP. To 

facilitate this proposed requirement, we 

are also proposing to clarify that fugitive 

emissions monitoring conducted to 

comply with NSPS OOOOa, NSPS 

OOOOb, or an applicable approved state 

plan or applicable Federal plan in 40 

CFR part 62 is considered a ‘‘complete 

leak detection survey,’’ so that onshore 

petroleum and natural gas production 

and onshore petroleum and natural gas 

gathering and boosting facilities can use 

NSPS OOOOb or 40 CFR part 62 fugitive 

emission surveys directly for their 

subpart W reports. In a corresponding 

amendment, we are also proposing to 

expand the current reporting 

requirement in 40 CFR 98.236(q)(1)(iii) 

to require reporters to indicate if any of 

the surveys of well sites or compressor 

stations used in calculating emissions 

under 40 CFR 98.233(q) were conducted 

to comply with the fugitive emissions 

standards in NSPS OOOOb or an 

applicable approved state plan or 

applicable Federal plan in 40 CFR part 

62.81 We request comment on these 

proposed amendments and whether 

there are other provisions or reporting 

requirements relative to NSPS OOOOb 

or EG OOOOc that we should consider 

for subpart W. 

Second, we are proposing to revise 40 

CFR 98.234(a) to clarify and consolidate 

the requirements for OGI and Method 21 

in 40 CFR 98.234(a)(1) and (2), 

respectively. In the 2016 amendments to 

subpart W (81 FR 4987, January 29, 

2016), the EPA added 40 CFR 

98.234(a)(6) and (7) to provide OGI and 

Method 21 as specified in NSPS OOOOa 

as leak detection survey methods. In 

part, structuring the amendment this 

way allowed the EPA to provide the 

NSPS OOOOa leak detection methods as 

allowable methods under subpart W 

without affecting the requirements for 

facilities and industry segments not 

subject to NSPS OOOOa. However, as 

the EPA continues to propose additional 

standards with slightly different 

variations on OGI and Method 21, it 

would be unnecessarily convoluted to 

continue to add those methods and 

cross-references to each standard to the 

end of 40 CFR 98.234(a). Therefore, the 

EPA is proposing to move 40 CFR 

98.234(a)(1) and 40 CFR 98.234(a)(6) to 

40 CFR 98.234(a)(1)(i) and 40 CFR 

98.234(a)(1)(ii), respectively, which 

would consolidate the OGI-based 

methods in 40 CFR 98.234(a)(1). 

Similarly, the EPA is proposing to revise 

40 CFR 98.234(a)(2) such that 40 CFR 

98.234(a)(2)(i) is Method 21 with a leak 

definition of 10,000 ppm and 40 CFR 

98.234(a)(2)(ii) is Method 21 with a leak 

definition of 500 ppm. This proposed 

amendment would effectively move 40 

CFR 98.234(a)(7) to 40 CFR 

98.234(a)(2)(ii). The references to 

‘‘components listed in § 98.232’’ would 

be replaced with a more specific 

reference to 40 CFR 98.233(q)(1). The 

references to specific provisions in 40 

CFR 60.5397a in 40 CFR 98.234(a)(6) 

and (7) would be moved to 40 CFR 

98.234(a)(1)(ii) and 40 CFR 98.234(a)(2), 

as applicable. 

The EPA proposed in NSPS OOOOb 

and EG OOOOc that owners and 

operators would detect leaks using an 

OGI-based monitoring method following 

the concurrently proposed appendix K 

to 40 CFR part 60. We are proposing to 

include that same method in subpart W 

at 40 CFR 98.234(a)(1)(iii) to ensure that 

reporters would be able to comply with 

the proposed subpart W requirement to 

use data derived from the NSPS OOOOb 

or 40 CFR part 62 fugitive emissions 

requirements for purposes of calculating 

emissions from equipment leaks. As 

part of the proposal of NSPS OOOOb 

and EG OOOOc, the EPA proposed an 

alternative screening approach for 

fugitive emissions from well sites and 

compressor stations that would allow 

the use of advanced measurement 

technologies to detect large equipment 

leaks. If emissions are detected using 

one of these advanced technologies, 

facilities would be required to conduct 

monitoring using OGI or Method 21 to 

identify and repair specific leaking 

equipment. Additionally, even if no 

large emissions are identified, facilities 

using these advanced technologies 

would still be required to conduct 

annual fugitive emissions monitoring 

using OGI or Method 21. The EPA’s 

intent in this proposed rule for subpart 

W is that the results of those NSPS 

OOOOb and 40 CFR part 62 OGI or 

Method 21 surveys would be used for 

purposes of calculating emissions for 

subpart W, as OGI and Method 21 are 

capable of identifying leaks from 

individual components and they are 

leak detection methods provided in 

subpart W. The EPA also requests 

comment on additional methods or 

advanced technologies that can identify 

individual leaking components. Based 

on the information received, the EPA 

would need to review the specific 

method and leak detection data 

collected using that method to 

determine what default leaker emission 

factors would apply for that method and 

whether any adjustments might be 

needed to the subpart W equipment leak 

survey calculation methodology when 

using that method. Following that 

review, the EPA may undertake a 

rulemaking process to include the 

additional leak detection method(s) in 

40 CFR 98.234(a). 

Third, we are proposing subpart W 

requirements for onshore natural gas 

processing facilities consistent with 

certain requirements for equipment 

leaks in the proposed NSPS OOOOb or 

EG OOOOc. Currently, onshore natural 

gas processing facilities must conduct at 

least one complete survey of all the 

components listed in 40 CFR 

98.232(d)(7) each year, and each 

complete survey must be considered 

when calculating emissions according to 

40 CFR 98.233(q)(2). Under the 

equipment leak detection and repair 

program included in proposed NSPS 

OOOOb and the EG OOOOc 

presumptive standards, different 

component types may be monitored on 

different frequencies, so all equipment 

at the facility is not always monitored 

at the same time. According to the 

current requirements in 40 CFR 

98.233(q), surveys that do not include 

all of the applicable equipment at the 

facility are not considered complete 

surveys and are not used for purposes 

of calculating emissions. Therefore, we 

are proposing that for onshore natural 

gas processing facilities subject to NSPS 

OOOOb or an applicable approved state 

plan or the applicable Federal plan in 

40 CFR part 62 would use the data 

derived from each equipment leak 

survey conducted as required by NSPS 

OOOOb or 40 CFR part 62 along with 

the subpart W equipment leak survey 

calculation methodology and leaker 

emission factors to calculate and report 

GHG emissions to the GHGRP, even if 

a survey required for compliance with 

NSPS OOOOb or 40 CFR part 62 does 

not include all the component types 

listed in 40 CFR 98.232(d)(7). 

Under this proposed amendment, 

reporters would still have to meet the 

subpart W requirement to conduct at 

least one complete survey of all 

applicable equipment at the facility per 

year, so if there were components listed 

in 40 CFR 98.232(d)(7) not included in 

any NSPS OOOOb or 40 CFR part 62- 

required surveys conducted during the 

year (e.g., connectors that are monitored 

only once every 4 years), reporters 


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82 Greenhouse Gas Emissions Reporting from the 

Petroleum and Natural Gas Systems Industry: 

Background Technical Support. November 2010. 

Docket Id. No. EPA–HQ–OAR–2009–0923–3610; 

also available in the docket for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424. 

83 Greenhouse Gas Reporting Rule: Technical 

Support for Leak Detection Methodology Revisions 

and Confidentiality Determinations for Petroleum 

and Natural Gas Systems. November 1, 2016. 

Docket Id. No. EPA–HQ–OAR–2015–0764–0066; 

also available in the docket for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424. 

84 Greenhouse Gas Reporting Rule: Technical 

Support for Leak Detection Methodology Revisions 

and Confidentiality Determinations for Petroleum 

and Natural Gas Systems. November 1, 2016. 

Docket Id. No EPA–HQ–OAR–2015–0764–0066; 

also available in the docket for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424. 

subject to NSPS OOOOb or 40 CFR part 

62 would need to either add those 

components to one of their required 

surveys, making that a complete survey 

for purposes of subpart W, or conduct 

a separate complete survey for purposes 

of subpart W. We expect that reporters 

with onshore natural gas processing 

plants implementing traditional leak 

detection and repair programs are 

already making similar decisions 

regarding how to meet the requirement 

to conduct a complete survey for 

subpart W, and our intention with this 

proposed amendment is not to change 

those decisions. Rather, this amendment 

would specify that surveys conducted 

pursuant to NSPS OOOOb or 40 CFR 

part 62 that do not include all 

component types listed in 40 CFR 

98.232(d)(7) would be used for 

calculating emissions along with each 

complete survey. 

We are also proposing to add leaker 

emission factors for all survey methods 

for ‘‘other’’ components that would be 

required to be monitored under NSPS 

OOOOb or an approved state plan or 

applicable Federal plan in 40 CFR part 

62 or that reporters elect to survey that 

are not currently included in subpart W. 

These proposed total hydrocarbon 

leaker emission factors are the same as 

the total hydrocarbon leaker emission 

factors for the Onshore Natural Gas 

Transmission Compression and the 

Underground Natural Gas Storage 

industry segments (Table W–3A and 

Table W–4A, respectively). For more 

information on the derivation of the 

original emission factors, see the TSD 

for the final subpart W standards,82 and 

for more information on the derivation 

of the emission factors proposed to be 

added to Table W–2B, see the TSD for 

the 2016 amendments to subpart W.83 In 

a corresponding amendment, we are 

also proposing to expand the reporting 

requirement in 40 CFR 98.236(q)(1)(iii) 

to require onshore natural gas 

processing reporters to indicate if any of 

the surveys used in calculating 

emissions under 40 CFR 98.233(q) were 

conducted to comply with the 

equipment leak standards in NSPS 

OOOOb or an applicable approved state 

plan or the applicable Federal plan in 

40 CFR part 62. We request comment on 

the proposed amendments to subpart W 

for onshore natural gas processing 

facilities subject to the equipment leak 

provisions of NSPS OOOOb or 40 CFR 

part 62, as well as whether there are 

other provisions or reporting 

requirements for these facilities that we 

should consider. 

Finally, in our review of subpart W 

equipment leak requirements for 

onshore natural gas processing facilities, 

we found that the leak definition for the 

Method 21-based requirements for 

processing plants in NSPS OOOOa (as 

well as proposed NSPS OOOOb and EG 

OOOOc presumptive standards) is not 

consistent with the leak definition in 

the Method 21 option in current 40 CFR 

98.234(a)(1), which is the only Method 

21-based method available to onshore 

natural gas processing facilities under 

subpart W. Based on this review, and to 

complement the proposed addition of 

default leaker emission factors for 

survey methods other than Method 21 

(as described previously in this 

preamble), we are proposing several 

additions to the equipment leak survey 

requirements for the Onshore Natural 

Gas Processing industry segment, 

beyond those amendments already 

described related to the proposed NSPS 

OOOOb and EG OOOOc presumptive 

standards. First, we are proposing 

default leaker emission factors for 

Method 21 at a leak definition of 500 

ppm in Table W–2A. As with the 

proposed ‘‘other’’ leaker emission 

factors, these proposed leaker emission 

factors are the same as the total 

hydrocarbon leaker emission factors for 

the Onshore Natural Gas Transmission 

Compression and the Underground 

Natural Gas Storage industry segments 

(Table W–3A and Table W–4A, 

respectively). For more information on 

the derivation of those emission factors, 

see the TSD for the 2016 amendments 

to subpart W.84 In addition, we are 

proposing to add 40 CFR 98.233(q)(1)(v) 

to indicate that onshore natural gas 

processing facilities not subject to NSPS 

OOOOb or an approved state plan or the 

applicable Federal plan in 40 CFR part 

62 may use any method specified in 40 

CFR 98.234(a), including Method 21 

with a leak definition of 500 ppm and 

OGI following the provisions of 

appendix K to 40 CFR part 60. This 

proposed amendment would ensure that 

equipment leak surveys conducted 

using any of the approved methods in 

subpart W would be available for 

purposes of calculating emissions, not 

just those surveys conducted using one 

of the methods currently provided in 40 

CFR 98.234(a)(1) through (5). 

l. Equipment Leaks by Population Count 

As noted in section III.J.1.k of this 

preamble, subpart W reporters are 

required to quantify emissions from 

equipment leaks using the calculation 

methods in 40 CFR 98.233(q) 

(equipment leak surveys) and/or 40 CFR 

98.233(r) (equipment leaks by 

population count), depending upon the 

industry segment. The equipment leaks 

by population count method uses the 

count of equipment components, 

subpart W emission factors (e.g., Table 

W–1A for the Onshore Petroleum and 

Natural Gas Production industry 

segment), and operating time to estimate 

emissions from equipment leaks. For the 

Onshore Petroleum and Natural Gas 

Production and Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segments, the count of 

equipment components may be 

determined by counting each 

component individually for each facility 

(Component Count Method 2) or the 

count of equipment components may be 

estimated using the count of major 

equipment and subpart W default 

average component counts for major 

equipment (Component Count Method 

1) in Tables W–1B and W–1C, as 

applicable. Reporters in other industry 

segments must count each applicable 

component at the facility. We are 

proposing several amendments to the 

calculation methodology provisions of 

40 CFR 98.233(r) and the reporting 

requirements in 40 CFR 98.236(r) to 

improve the quality of the data 

collected, consistent with sections 

II.A.1, II.A.4, and II.A.5 of this 

preamble. 

Onshore petroleum and natural gas 

production and onshore petroleum and 

natural gas gathering and boosting 

population count method. The current 

population emission factors for the 

Onshore Petroleum and Natural Gas 

Production and Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segments are found in Table 

W–1A of subpart W. The gas service 

population emission factors are based 

on the 1996 Gas Research Institute 

(GRI)/EPA study Methane Emissions 

from the Natural Gas Industry, Volume 

8: Equipment Leaks (available in the 

docket for this rulemaking, Docket Id. 

No. EPA–HQ–OAR–2019–0424). The oil 

service population emission factors are 

based on the American Petroleum 

Institute’s (API) Emission Factors for Oil 


jspears on DSK121TN23PROD with PROPOSALS2
36980 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

85Pacsi, A. P. et al. Equipment leak detection and 

quantification at 67 oil and gas sites in the Western 

United States. Elementa (2019). https://doi.org/ 

10.1525/elementa.368. Available in the docket for 

this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

86Zimmerle, D., et al. Methane Emissions from 

Gathering Compressor Stations in the U.S. 

Environmental Science & Technology 54 (12), 

7552–7561 (2020). https://doi.org/10.1021/ 

acs.est.0c00516. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

87Rutherford, J.S., Sherwin, E.D., Ravikumar, 

A.P. et al. Closing the methane gap in US oil and 

natural gas production inventories. Nat Commun 

12, 4715 (2021). https://doi.org/10.1038/s41467- 

021-25017-4. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

and Gas Production Operations, 

Publication 4615 published in 1995. 

As noted previously in this section, 

when estimating emissions using the 

population count method, onshore 

petroleum and natural gas production 

facilities and onshore petroleum and 

natural gas gathering and boosting 

facilities have the option to use actual 

component counts (i.e., Component 

Count Method 2) or to estimate their 

component counts using the count of 

major equipment (e.g., wellhead) and 

default component counts per major 

equipment (e.g., valves per wellhead) 

included in Tables W–1B and W–1C of 

subpart W (i.e., Component Count 

Method 1). In reviewing subpart W data, 

we find that the vast majority (greater 

than 95 percent) of onshore production 

and natural gas gathering and boosting 

facilities use Component Count Method 

1 to estimate the count of components. 

It is important to note that both the 

population count emission factors and 

the default component counts per major 

equipment included in Tables W–1A, 

W–1B and W–1C are service-specific 

(i.e., gas or oil) as well as region-specific 

(i.e., eastern or western U.S.). The 

regional designations are provided by 

U.S. state in Table W–1D of subpart W 

such that a facility would determine the 

facility’s region and select the 

appropriate region- and service-specific 

factors. 

In the years that have followed the 

adoption of these emission factors into 

subpart W, there have been numerous 

studies regarding emissions from 

equipment leaks at onshore production 

and gathering and boosting facilities. 

Two recent field studies, Pacsi et al. 

(2019) 85 and Zimmerle et al. (2020),86

have performed an equipment and 

component inventory alongside 

equipment leak screening and 

measurement results. Another recent 

study, Rutherford et al. (2021),87

included synthesis and analysis of 

measurements from component-level 

field studies. These studies provide the 

necessary data to develop and compare 

study-estimated population emission 

factors as well as study-estimated 

default component counts per major 

equipment to those in subpart W. 

Comparison of the study-estimated 

default component counts per major 

equipment found that the subpart W 

values underestimate the count of 

components found on major equipment 

in the field (Zimmerle et al., 2020; Pacsi 

et al., 2019). Regarding a comparison of 

the population emission factors and 

component counts per major equipment 

between the subpart W eastern and 

western values, Zimmerle et al. (2020) 

was the only field study to include both 

eastern and western facilities, and the 

study values showed ‘‘no statistically 

significant differences between eastern 

and western U.S. regions.’’ Rutherford et 

al. (2021) also found their studyestimated population emission factors to 

be higher than those in subpart W, 

noting that one of the contributing 

factors to this difference was the use of 

the eastern factors in subpart W, which 

appear to significantly undercount 

emissions. Rutherford et al. (2021) 

noted that the impact of the use of the 

eastern factors has grown over time as 

the production in the eastern region of 

the U.S. has increased from less than 5 

percent of gas produced to nearly 30 

percent of the gas produced. 

Based on our review of these studies, 

we are proposing to amend the 

population count method for onshore 

petroleum and natural gas production 

and onshore petroleum and natural gas 

gathering and boosting facilities using 

these more recent study data, consistent 

with section II.A.1 of this preamble. 

These proposed amendments include 

new population emission factors that 

are on a per major equipment basis 

rather than a per component basis. As 

mentioned previously, the vast majority 

of reporters estimate the component 

counts using Component Count Method 

1. By providing emission factors on a

major equipment basis instead of by

component, we would eliminate the

step to estimate the number of

components. All facilities would be able

to inventory their major equipment and

consistently apply the same emissions

factor to estimate emissions. This would

reduce reporter burden and reduce the

number of errors in the calculation of

emissions, as we find that numerous

facilities incorrectly estimate the

number of components using

Component Count Method 1 while

providing consistently estimated

emission results. The major equipment

emission factors were developed by

combining data from Zimmerle et al. 

(2020) and Pacsi et al. (2019) to provide 

population emission factors by major 

equipment and site type (i.e., gas or oil). 

The emission factors were derived by 

summing the leaker emissions by major 

equipment type, including wellhead, 

separator, meters/piping, compressor, 

acid gas removal unit, dehydrator, 

header, heater treater, and storage 

vessel, by the reported site type and 

dividing those leaker emissions by the 

count of major equipment screened to 

yield an emission factor in units of scf 

whole gas/hour-equipment. Specific to 

meters/piping and consistent with 

current requirements related to meters/ 

piping at 40 CFR 98.233(r)(2)(i)(A), we 

are proposing in 40 CFR 98.233(r)(2) to 

specify that one meters/piping 

equipment should be included per wellpad for onshore petroleum and natural 

gas production operations and the count 

of meters in the facility should be used 

for this equipment category at onshore 

petroleum and natural gas gathering and 

boosting facilities. As a consequence of 

the broader scope of equipment 

surveyed in the Pacsi/Zimmerle studies, 

the proposed emission factors include 

more pieces of major equipment than 

are currently included in subpart W. 

The derivation of the proposed emission 

factors is discussed in more detail in the 

subpart W TSD, available in the docket 

for this rulemaking, Docket Id. No. 

EPA–HQ–OAR–2019–0424. The 

proposed major equipment emission 

factors would replace the componentbased emission factors in the current 

Table W–1A. We are also proposing to 

revise the titles of Tables W–1B, W–1C, 

and W–1D to clarify that they apply to 

reporting years up to and including 

RY2022. These tables would not apply 

to subsequent reporting years as they 

provide activity data that would no 

longer be needed for the population 

count method for these industry 

segments. We are seeking comment on 

the approach of providing population 

count emission factors by major 

equipment. 

We note that the application of these 

emission factors is by site type such that 

for onshore petroleum and natural gas 

production facilities, gas well sites 

should use the proposed gas service 

emission factors and oil well sites 

should use the proposed oil service 

emission factors. Similarly, for onshore 

petroleum and natural gas gathering and 

boosting facilities, we consider all 

equipment to be in gas service 

consistent with the language in 40 CFR 

98.233(r)(2); thus, the proposed gas 

service factors from Table W–1A should 

be applied to all equipment counts. We 


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88 GRI/EPA. Methane Emissions from the Natural 

Gas Industry, Volume 9: Underground Pipelines. 

Prepared for Gas Research Institute and U.S. 

Environmental Protection Agency National Risk 

Management Research Laboratory by L.M. 

Campbell, M.V. Campbell, and D.L. Epperson, 

Radian International LLC. GRI–94/0257.2b, EPA– 

600/R–96–080i. June 1996. Available in the docket 

for this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

89 ICF. Fugitive Emissions from Plastic Pipe, 

Memorandum from H. Mallya and Z. Schaffer, ICF 

Consulting to L. Hanle and E. Scheehle, EPA. June 

30, 2005. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

90 GRI/EPA. Methane Emissions from the Natural 

Gas Industry, Volume 10: Metering and Pressure 

Regulating Stations in Natural Gas Transmission 

and Distribution. Prepared for Gas Research 

Institute and U.S. Environmental Protection Agency 

National Risk Management Research Laboratory by 

L.M. Campbell and B.E. Stapper, Radian 

International LLC. GRI–94/0257.27, EPA–600/R– 

96–080j. June 1996. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

91U.S. EPA. Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: Revisions under 

Consideration for Natural Gas Distribution 

Emissions. December 2015. Available at https://

www.epa.gov/sites/production/files/2016-02/ 

documents/proposed_revisions_to_ng_distribution_

segment_emissions.pdf and in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

92U.S. EPA. Inventory of U.S. Greenhouse Gas 

Emissions and Sinks 1990–2014: Revisions to 

Natural Gas Distribution Emissions. April 2016. 

Available at https://www.epa.gov/sites/production/ 

files/2016-08/documents/final_revision_ng_

distribution_emissions_2016-04-14.pdf and in the 

docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

93Lamb, B.K. et al. ‘‘Direct Measurements Show 

Decreasing Methane Emissions from Natural Gas 

Local Distribution Systems in the United States.’’ 

Environ. Sci. Technol. 2015, 49, 5161–5169. 

Available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

94Weller, Z.D.; Hamburg, S.P.; and Von Fischer, 

J.C. 2020. ‘‘A National Estimate of Methane Leakage 

from Pipeline Mains in Natural Gas Local 

Distribution Systems.’’ Environ. Sci. Technol. 2020, 

54(1), 8958. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

are proposing language clarifying the 

service-specific application of these 

emission factors specifically for onshore 

petroleum and natural gas production in 

40 CFR 98.233(r)(2). 

Natural Gas Distribution Emission 

Factors. Natural Gas Distribution 

companies quantify the emissions from 

equipment leaks from pipeline mains 

and services, below grade transmission 

distribution transfer stations, and below 

grade metering-regulating stations 

following the procedures in 40 CFR 

98.233(r). This method uses the count of 

equipment, subpart W population 

emission factors in Table W–7 

(proposed to be moved to Table W–8), 

and operating time to estimate 

emissions. The population emission 

factors for pipeline mains and services 

in Table W–7 (proposed to be moved to 

Table W–8) are based on information 

from the 1996 GRI/EPA study.88

Specifically for plastic mains, additional 

data are sourced from a 2005 ICF 

analysis.89 The population emission 

factors for pipeline mains are published 

per mile of main by pipeline material 

and emission factors for pipeline 

services are published per service by 

pipeline material. The population 

emission factors for below grade stations 

in Table W–7 (proposed to be moved to 

Table W–8) are based on information 

from the 1996 GRI/EPA study.90 The 

population emission factors for below 

grade transmission-distribution transfer 

stations and below grade meteringregulating stations are published per 

station by three inlet pressure categories 

(>300 psig, 100–300 psig, <100 psig). 

The EPA is proposing to update the 

population emission factors in Table W– 

7 (proposed to be moved to Table W– 

8) to subpart W using the results of 

studies and information that were not 

available when the rule was finalized in 

2010. Notably, the EPA reviewed recent 

studies and updated the emission 

factors for several natural gas 

distribution sources, including pipeline 

mains and services and below grade 

stations, for the 2016 U.S. GHG 

Inventory.91 92 The majority of the U.S. 

GHG Inventory updates were based on 

data published by Lamb et al. in 2015.93

Since the time that the 2016 U.S. GHG 

Inventory updates were made, 

additional studies for pipeline 

distribution mains have been published 

and reviewed by the EPA, notably 

Weller et al. in 2020.94 Our assessment 

of the studies published since subpart 

W was finalized supports revising the 

emission factors for pipelines in the 

Natural Gas Distribution industry 

segment of subpart W. For more 

information on the review and analysis 

of the various studies, see the subpart W 

TSD, available in the docket for this 

rulemaking (Docket Id. No. EPA–HQ– 

OAR–2019–0424). 

The population emission factors for 

distribution mains and services are a 

function of the average measured leak 

rate (scf/hr) and the frequency of annual 

leaks observed (leaks/mile-year or leaks/ 

service-year) by pipeline material (e.g., 

protected steel, plastic). The Lamb et al. 

and Weller et al. studies utilized 

different approaches for quantifying 

leak rates and determining the pipeline 

material-specific frequency of annual 

leaks. The Lamb et al. study quantified 

leaks from distribution mains and 

services using a high volume sampling 

method and some downwind tracer 

measurements and estimated the 

frequency of leaks by pipeline material 

using company records and Department 

of Transportation (DOT) repaired leak 

records from six local distribution 

companies (LDCs). This methodology 

was consistent with the GRI/EPA study. 

The Weller et al. study quantified leaks 

from only distribution mains using the 

Advanced Mobile Leak Detection 

(AMLD) technique, which involves 

mobile surveying using high sensitivity 

instruments and algorithms that predict 

the leak location and size, attributed 

leaks to the pipeline material using 

geographic information system (GIS) 

data, and estimated the frequency of 

leaks using modeling. 

During our assessment of the Lamb et 

al. and Weller et al. studies, we 

identified the method for leak 

quantification as being a key strength of 

the Lamb et al. study and the 

significantly larger sample size used in 

estimating the annual leak frequency as 

being a key strength of the Weller et al. 

study. In order to take advantage of the 

strengths of both studies, we are 

proposing to amend the subpart W 

emission factors for distribution mains 

using the measurements from Lamb et 

al. combined with the pipeline material 

specific leaks per mile data from Weller 

et al. We are proposing to amend the 

subpart W emission factors for 

distribution services using the 

measurements from Lamb et al. only, 

consistent with the emission factors 

used in the 2016 U.S. GHG Inventory, 

because services were not included in 

the Weller et al. study. See the subpart 

W TSD, available in the docket for this 

rulemaking (Docket Id. No. EPA–HQ– 

OAR–2019–0424) for more information 

on our assessment of both studies and 

the derivation of the proposed emission 

factors from the data published by Lamb 

et al. and Weller et al. We are seeking 

comments on the approach of 

combining data from both studies to 

update the distribution mains emission 

factors. As alternatives to the proposed 

amendments, we also considered 

updating the distribution mains 

emission factors using data from each 

study independently. Accordingly, we 

are also seeking comment on whether 

using data only from Lamb et al., 

consistent with the emission factors 

used in the U.S. GHG Inventory, or only 

from Weller et al. to update the 

distribution mains emission factors 

would be preferable over the combined 

approach included in this proposal, and 

if so, which study is preferred and why. 

For below grade stations, the 2016 

U.S. GHG Inventory also began applying 

a new emission factor from the data 

published by Lamb et al. to the count of 

stations to estimate emissions from 

these sources. In order to assess the 


jspears on DSK121TN23PROD with PROPOSALS2
36982 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

95 GRI/EPA. Methane Emissions from the Natural 

Gas Industry, Volume 9: Underground Pipelines. 

Prepared for Gas Research Institute and U.S. 

Environmental Protection Agency National Risk 

Management Research Laboratory by L.M. 

Campbell, M.V. Campbell, and D.L. Epperson, 

Radian International LLC. GRI–94/0257.2b, EPA– 

600/R–96–080i. June 1996. Available in the docket 

for this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

96Lamb, B.K. et al. ‘‘Direct Measurements Show 

Decreasing Methane Emissions from Natural Gas 

Local Distribution Systems in the United States.’’ 

Environ. Sci. Technol. 2015, 49, 5161–5169. 

Available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

97The EPA notes that the full emissions from this 

event were included in the U.S. GHG Inventory 

based on the results of multiple measurement 

studies. 

appropriateness of incorporating this 

revision into the subpart W 

requirements for below grade stations 

(i.e., replacing the set of below grade 

emission factors by station type and 

inlet pressure with one single emission 

factor), the EPA performed an analysis 

of the reported subpart W data for below 

grade stations compared to data from 

the recent studies (see the subpart W 

TSD, available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424). We found that the 

subpart W reported station count 

combined with the current subpart W 

emission factors yields an average 

emission factor similar to the U.S. GHG 

Inventory emission factor; as such, 

using either set of emission factors 

would yield approximately the same 

emissions results for the GHGRP. 

Therefore, we are proposing to amend 

the emission factors for below grade 

transmission-distribution transfer 

stations and below grade meteringregulating stations in Table W–7 

(proposed to be moved to Table W–8) to 

a single emission factor without regard 

to inlet pressure. We are also proposing 

to amend the corresponding section 

header in Table W–7 (proposed to be 

moved to Table W–8) for below grade 

station emission factors and the 

references to Table W–7 (proposed to be 

moved to Table W–8) in 40 CFR 

98.233(r)(6)(i) to clarify the emission 

factor that should be applied to both 

types of below grade stations (i.e., 

transmission-distribution transfer and 

metering-regulating). This proposed 

amendment would impact the reporting 

requirements as well, as it would 

consolidate six emission source types to 

two emission source types (below grade 

transmission-distribution transfer 

stations and below grade meteringregulating stations, without 

differentiating between inlet pressures) 

for purposes of reporting under 40 CFR 

98.236(r)(1). This proposed amendment 

would improve the data quality through 

use of more recent emission factors and 

would be consistent with changes made 

to the U.S. GHG Inventory. It would also 

result in reporting of fewer data 

elements, consistent with section II.B.3 

of this preamble. 

Gathering pipeline emission factors. 

Facilities in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segment quantify the emissions 

from equipment leaks from gathering 

pipelines following the procedures in 40 

CFR 98.233(r). This method uses the 

count of equipment, subpart W 

population emission factors in Table W– 

1A, and operating time to estimate 

emissions. The population emission 

factors for gathering pipeline mains in 

Table W–1A are based on leak rates 

from natural gas distribution companies 

and gathering pipeline-specific activity 

data as provided in the 1996 GRI/EPA 

study.95 The population emission 

factors for gathering pipelines are 

published per mile by pipeline material. 

As noted previously in this section, 

the EPA is proposing to update the 

natural gas distribution population 

emission factors in Table W–7 

(proposed to be moved to Table W–8) to 

subpart W using the results of studies 

and information that were not available 

when the rule was originally finalized. 

In particular, the EPA is proposing to 

update the leak rate portion of the 

emission factor based on data published 

by Lamb et al. in 2015.96 The EPA has 

reviewed the recent studies published 

for onshore petroleum and natural gas 

gathering and boosting facilities as well 

as the additional studies for pipeline 

distribution mains, and none of the 

studies provide new emissions data or 

activity data specific to gathering 

pipelines. Therefore, consistent with the 

updates to the emission factors for 

distribution mains, and consistent with 

section II.A.1 of this preamble, we are 

proposing to revise the gathering 

pipeline population emission factors to 

use the leak rates from Lamb et al. 

(2015). We are not proposing to update 

the activity data (leaks per mile of 

pipeline) portion of the emission 

factors, as the information in the 1996 

GRI/EPA study continues to be the best 

available data specific to gathering 

pipelines. For more information on the 

proposed updates to the gathering 

pipeline population emission factors, 

see the subpart W TSD, available in the 

docket for this rulemaking (Docket Id. 

No. EPA–HQ–OAR–2019–0424). 

m. Other Large Release Events 

We are proposing to add an additional 

emissions source, referred to as ‘‘other 

large release events’’ to capture 

abnormal emission events that are not 

fully accounted for using existing 

methods in subpart W, consistent with 

section II.A.3 of this preamble. Most of 

the emission sources and methodologies 

included in subpart W characterize 

emissions that routinely occur at oil and 

gas facilities as part of their normal 

operations. While some sources covered 

by subpart W methodologies, such as 

equipment leaks, may represent 

‘‘malfunctioning’’ equipment, these 

sources are ubiquitous across the oil and 

gas sector, are generally small, and have 

been studied and characterized. On the 

other hand, there have been several 

large, atypical release events at oil and 

gas facilities over the last few years 

where it was difficult to sufficiently 

include these emissions in annual 

GHGRP reports. For example, a storage 

wellhead leak at Aliso Canyon released 

approximately 100,000 metric tons of 

CH4 between October 2015 and 

February 2016 and a well blowout in 

Ohio released an estimated 40,000 to 

60,000 tons of CH4 in a 20-day period 

in 2018. The emissions from these types 

of releases were not well represented 

using the existing calculation 

methodologies in subpart W because 

these were not common or predictable 

events.97 Because these events can 

significantly contribute to the total GHG 

emissions from this sector, we are 

proposing new calculation methods for 

estimating the GHG emissions from 

other large release events in 40 CFR 

98.233(y) and requirements for reporting 

other large release events in 40 CFR 

98.236(y). These proposed additional 

calculation and reporting requirements 

would apply to all subpart W industry 

segments and would improve the 

accuracy of emissions reported under 

subpart W and enhance the overall 

quality of the data collected under the 

GHGRP. 

The new calculation requirements 

being proposed rely on measurement 

data or engineering estimates of the 

amount of gas released and 

measurement data, if available, or 

process knowledge (best available data) 

to estimate the composition of the 

released gas. The proposed requirement 

to calculate and report GHG emissions 

from other large release events would be 

limited to events that release at least 250 

mtCO2e per event. This is equivalent to 

approximately 500,000 scf of pipeline 

quality natural gas. We selected this 

proposed threshold to capture reporting 

for large emission events, such as well 

blowouts, well releases, and large 

pressure relief venting. In order to 

establish this reporting threshold, we 

first assessed other emission sources 

that we considered large. Specifically, 


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we considered completions of 

hydraulically fractured wells that are 

not controlled (i.e., not performed using 

reduced emission completions) to be 

large emissions events. Based on 

analysis of GHGRP data of wells that are 

not reduced emission completions and 

that vent, the U.S. GHG Inventory 

developed an average emission factor of 

about 360 mtCO2e for these events. 

Because this is an average emissions 

factor, some uncontrolled hydraulically 

fractured completions will be below this 

average and some above. From this 

assessment, we considered 250 mtCO2e 

to be a reasonable emissions threshold 

for a ‘‘large’’ event. 

While 250 mtCO2e is much lower 

than the emissions from the Aliso 

Canyon or Ohio well blowout releases, 

we determined that a 250 mtCO2e 

threshold would be needed to capture 

most well blowouts. There are limited 

data to quantify an ‘‘average’’ well 

blowout, but the 2021 U.S. GHG 

Inventory uses an oil well blowout 

emission factor of 2.5 MMscf per event. 

As this is an average, many well 

blowouts will be less than this average 

value. The 250 mtCO2e threshold is 

approximately equivalent to 500,000 scf 

of natural gas, which compares 

reasonably well with the lower range of 

well blowouts expected based on the 

average emission factor of 2.5 MMscf 

per event. 

We also find that the 250 mtCO2e 

threshold (approximately equivalent to 

500,000 scf natural gas release) is a 

reasonable threshold for requiring 

individual assessments of releases. In 

subpart Y (Petroleum Refineries), we 

established event-specific emission 

calculation requirements for startup, 

shutdown, or malfunction releases to a 

flare exceeding 500,000 scf per day (40 

CFR 98.253(b)(1)(iii)). While the subpart 

Y threshold is per day rather than per 

event, it is also specific to flared 

emissions. For flared emissions to 

exceed a 250 mtCO2e threshold, 

approximately 4 MMscf of natural gas 

would have to be released to the flare, 

which is well above the subpart Y ‘‘per 

day’’ threshold for flares. Thus, we 

conclude that the 250 mtCO2e per event 

threshold is an appropriate size 

threshold for requiring event-specific 

emission calculations to be performed. 

More information regarding our review 

and characterization of types of other 

large release events is included in the 

subpart W TSD, available in the docket 

for this rulemaking, Docket Id. No. 

EPA–HQ–OAR–2019–0424. Emissions 

from smaller or routine release events 

would still be reported, as applicable, 

under the source-specific calculation 

and reporting requirements in subpart 

W. 

We are proposing a definition of 

‘‘other large release events’’ in 40 CFR 

98.238 to clarify the types of releases 

that must be characterized for this new 

emissions source and specify that other 

large release events include, but are not 

limited to, well blowouts, well releases, 

releases from equipment rupture, fire, or 

explosions. Currently, there are no 

calculation methodologies or reporting 

requirements for these types of large 

releases in subpart W. The proposed 

definition would also include large 

pressure relief valve releases from 

process equipment other than onshore 

production and onshore petroleum and 

natural gas gathering and boosting 

storage tanks that are not included in 

the blowdown definition. While subpart 

W currently includes emission factors 

for pressure relief devices, these 

equipment leak emission factors only 

account for leaks past a pressure relief 

valve that is in the closed position, not 

releases from the complete opening of 

these valves. The proposed definition 

specifies that pressure relief valve 

releases from onshore production and 

onshore petroleum and natural gas 

gathering and boosting storage tanks 

would not be considered other large 

release events because the calculation 

methodology for these storage tanks 

currently assumes all flash gas will be 

emitted. As noted in section III.K.1.g of 

this preamble, pressure relief emission 

releases from onshore production and 

onshore petroleum and natural gas 

gathering and boosting storage tanks 

generally occur from the thief hatch and 

these releases must be accounted for 

when calculating the fraction of flash 

gas that is recovered or sent to a flare, 

if applicable. A more detailed 

discussion of certain other emissions 

events we have identified and expect to 

be subject to the ‘‘other large release 

events’’ proposed amendments is 

included in the subpart W TSD 

available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. 

As part of the proposed definition of 

‘‘other large release events’’ in 40 CFR 

98.238, we are also proposing that other 

large release events include releases 

from equipment for which the existing 

calculation methodologies in subpart W 

would significantly underestimate the 

episodic nature of these emissions. For 

example, subpart W contains population 

emission factors and leaker emission 

factors for estimating equipment leak 

emissions for storage wellheads. Thus, it 

is possible to argue that subpart W 

includes calculation methodologies for 

the equipment responsible for the Aliso 

Canyon release. However, the 

calculation methodologies in subpart W 

do not accurately estimate emissions 

from such an uncharacteristically large 

event because such events are so rare 

that they generally do not exist when 

measurement studies are conducted. 

Additionally, skewing the emission 

factors used to account for such an 

event would yield erroneously high 

emissions from normal operations for 

nearly all reporting facilities. Thus, we 

determined that it is more accurate for 

facility-specific reporting to account for 

these large releases on a per event basis. 

Therefore, if a single leak or event has 

emissions that exceed the emissions 

estimated by an applicable methodology 

included in subpart W by 250 mtCO2e 

or more, we are proposing that such 

releases would be included in the 

definition of ‘‘other large release events’’ 

and that reporters would be required to 

calculate and report the GHG emissions 

from these events using the proposed 

requirements for other large release 

events. 

Further, we are proposing to define 

the terms ‘‘well release’’ and ‘‘well 

blowout’’ in 40 CFR 98.238 to assist 

reporting facilities with differentiating 

between these types of release events 

that could potentially occur at wells. We 

find that a well blowout is generally 

distinguished by a complete loss of well 

control for a long duration of time and 

a well release is characterized as a short 

period of uncontrolled release (not the 

controlled pre-separation stage of well 

flowback in a hydraulically fractured 

completion) followed by a period of 

controlled release in which control 

techniques were successfully 

implemented. 

Finally, we are proposing a reporting 

requirement that would require subpart 

W reporters to indicate whether an 

‘‘other large release event’’ was 

identified under any provisions of NSPS 

OOOOb or an applicable approved state 

plan or applicable Federal plan in 40 

CFR part 62. As described in section 

III.J.1.k of this preamble, the EPA 

proposed a fugitive emissions 

monitoring program in NSPS OOOOb 

and EG OOOOc, including an 

alternative screening approach for 

fugitive emissions from well sites and 

compressor stations that would allow 

the use of advanced measurement 

technologies to detect emissions. As 

part of that proposal, the EPA also 

requested comment on how to evaluate 

and design a requirement for owners 

and operators to investigate and 

remediate large emission events, which 

could include the use of alternative 

screening techniques and advanced 

measurement technologies, all of which, 


jspears on DSK121TN23PROD with PROPOSALS2
36984 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

98Zimmerle et al., Characterization of Methane 

Emissions from Gathering Compressor Stations: 

Final Report (October 2019 Revision) and Vaughn 

et al., ‘‘Methane Exhaust Measurements at 

Gathering Compressor Stations in the United 

States,’’ Environmental Science & Technology. 

2021, 55 (2), 1190–1196, both available in the 

docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

99See section III.J.2.f of this preamble for 

information on the proposed amendments to 40 

CFR 98.233(z) to increase the flexibility for 

reporters to use the subpart C calculation 

methodologies. 

100See Letter from GPA Midstream Association to 

Mark de Figueiredo, U.S. EPA, providing 

information in response to EPA questions during 

the meeting on March 23, 2016. May 18, 2016. See 

also Letter from Matt Hite, GPA Midstream 

Association, to Mark de Figueiredo, U.S. EPA, Re: 

Additional Information on Suggested Part 98, 

Subpart W Rule Revisions to Reduce Burden. 

September 13, 2019. Both letters are available in the 

docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

if finalized, could potentially be used to 

identify ‘‘other large release events’’ 

under subpart W. While some methods 

that could be used to identify and 

estimate the magnitude of these ‘‘other 

large release events,’’ such as monitors 

installed on mobile vehicles or aircraft 

or methane satellite imagery, would not 

be specifically included as measurement 

methods in subpart W, these methods 

may be used to quantify the emissions 

release for ‘‘other large release events’’ 

under the ‘‘engineering estimates’’ and 

‘‘best available data’’ provisions of the 

proposed calculation methodology. To 

improve the EPA’s understanding of the 

technologies and methods used to 

identify reported ‘‘other large release 

events,’’ including the impact of 

periodic screenings with advanced 

measurement technologies on the 

identification of large release events, we 

are proposing reporting provisions that 

would require reporters to indicate 

whether each ‘‘other large release event’’ 

was identified as part of compliance 

with NSPS OOOOb or the applicable 

state plan or applicable Federal plan in 

40 CFR part 62. 

n. Combustion 

Methane slip from compressor 

engines. All facilities reporting under 

subpart W except those in the Onshore 

Natural Gas Transmission Pipeline 

industry segment must include 

combustion emissions in their annual 

report. Facilities in the Onshore 

Petroleum and Natural Gas Production, 

Onshore Petroleum and Natural Gas 

Gathering and Boosting, and Natural 

Gas Distribution industry segments 

calculate emissions in accordance with 

the provisions in 40 CFR 98.233(z) and 

report combustion emissions per 40 CFR 

98.236(z). Reporters in the other 

industry segments calculate and report 

combustion emissions under subpart C 

(General Stationary Fuel Combustion 

Sources). The authors of several recent 

studies have examined combustion 

emissions at Onshore Petroleum and 

Natural Gas Gathering and Boosting 

facilities and have demonstrated that a 

significant portion of emissions can 

result from unburned methane 

entrained in the exhaust of natural gas 

compressor engines (also referred to as 

‘‘combustion slip’’ or ‘‘methane slip’’). 

These studies contend that emissions 

from natural gas compressor engines 

included in the GHGRP are significantly 

underestimated because they do not 

account for combustion slip.98 The EPA 

performed a review of each of these 

studies and the U.S. GHG Inventory to 

determine whether and how combustion 

slip emissions have been incorporated 

into published data and how the 

incorporation of combustion slip would 

affect the emissions from the petroleum 

and natural gas system sector reported 

to the GHGRP (see the subpart W TSD, 

available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424). 

Based on the EPA’s review and 

analysis, there appears to be combustion 

slip for all compressor engine types at 

oil and gas facilities. In addition, while 

the recent studies are focused on the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting industry 

segment, the EPA’s literature review 

found the presence of combustion slip 

in different industry segments, so it 

appears that combustion slip is 

dependent on the type of engine and not 

the application (i.e., we expect 

combustion slip from compressor 

engines regardless of the industry 

segment). Therefore, the EPA is 

proposing to revise the methodologies 

for determining combustion emissions 

from compressor engines to account for 

combustion slip, consistent with section 

II.A.3 of this preamble. For the three 

subpart W industry segments that 

calculate combustion emissions per 40 

CFR 98.233(z), we are proposing to 

accomplish this with two amendments 

to the calculation methods and the 

addition of one new reporting 

requirement. For compressor engines in 

those subpart W industry segments that 

combust natural gas and qualify to 

determine emissions using the subpart C 

calculation methodologies per 40 CFR 

98.233(z)(1) and proposed new 

98.233(z)(2),99 we are proposing that 

reporters would use subpart-W specific 

emission factors by engine design class 

(e.g., 2-stroke lean-burn, 4-stroke leanburn, 4-stroke rich-burn, or other) in 

proposed new Table W–9 rather than 

the emission factors in Table C–2. For 

compressor engines that combust 

natural gas and determine emissions per 

40 CFR 98.233(z)(2) (proposed to be 

moved to 40 CFR 98.233(z)(3)), we are 

proposing updated combustion 

efficiency value(s) (h) by engine design 

class to be used in equations W–39A 

and W–39B that would reflect 

combustion slip. We are also proposing 

to add a reporting requirement to 40 

CFR 98.233(z)(2) to specify the design 

class of reported internal combustion 

units that are compressor-drivers to 

facilitate verification of the selected 

emission factors and efficiencies, as 

applicable, and the resulting emissions. 

In an analogous amendment for the 

reporters in the other subpart W 

industry segments that calculate and 

report combustion emissions under 

subpart C, we are proposing that they 

also use subpart W-specific emission 

factors rather than the emission factors 

in Table C–2. Currently, these facilities 

use either equation C–8, C–8a, C–8b, C– 

9, C–9a, C–9b, or C–10 in 40 CFR 

98.33(c), as it corresponds to the Tier 

methodology selected to estimate their 

CO2 emissions, to estimate CH4

emissions. These equations rely on the 

use of a default CH4 emission factor 

from Table C–2 to estimate emissions. 

As described in section III.B of this 

preamble, the emission factor term 

definition in each of these equations is 

proposed to be amended to reference 

Table W–9 rather than Table C–2 

specifically for quantifying emissions 

from compressor-drivers. We are also 

proposing to add a footnote to Table C– 

2 to specify that the default CH4

emission factor should only be used for 

combustion devices that are not 

compressor-drivers. 

Clarifications of calculation 

methodologies. As noted previously in 

this section, Onshore Petroleum and 

Natural Gas Production, Onshore 

Petroleum and Natural Gas Gathering 

and Boosting, and Natural Gas 

Distribution facilities report combustion 

emissions calculated in accordance with 

40 CFR 98.233(z) instead of reporting 

under subpart C. Stakeholders (e.g., 

GPA Midstream) have identified several 

concerns with the requirements in 40 

CFR 98.233(z). First, GPA Midstream 

has indicated that for fuels using the 

existing provisions of 40 CFR 

98.233(z)(2) to calculate emissions, the 

requirements for determining the gas 

composition could result in inaccurate 

calculations of emissions for some 

facilities.100 In particular, 40 CFR 

98.233(z)(2)(ii) currently specifies that 

to determine the concentrations of 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 36985 

101Letter from GPA Midstream Association to 

Mark de Figueiredo, U.S. EPA, providing 

information in response to EPA questions during 

the meeting on March 23, 2016. May 18, 2016. 

Available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

hydrocarbon constituents in the flow of 

gas to the unit, reporters must either use 

a continuous gas composition analyzer 

(if one is present) or the procedures in 

the applicable paragraph in 40 CFR 

98.233(u)(2) of this section. For onshore 

petroleum and natural gas gathering and 

boosting facilities, 40 CFR 98.233(u)(2) 

specifies use of the annual average gas 

composition based on the most recent 

available analysis of the gas received at 

the facility. However, GPA Midstream 

explained that onshore petroleum and 

natural gas gathering and boosting 

facilities do not necessarily use the gas 

received at their facility for combustion. 

For example, if the gas received at the 

facility is not suitable for combustion, 

they may mix the gas with purchased 

natural gas. In that case, the annual 

average composition of gas received at 

the facility would not be representative 

of the gas sent to the combustion unit 

(as required by 40 CFR 98.233(z)(2)), 

which could result in inaccurate 

emissions. Therefore, the EPA is 

proposing to revise the language in 40 

CFR 98.233(z)(2)(ii) (proposed to be 

moved to 40 CFR 98.233(z)(3)(ii)(B)) to 

allow the use of engineering estimates 

based on best available data to 

determine the concentration of gas 

hydrocarbon constituent in the flow of 

gas to the unit. This proposed 

amendment would allow reporters to 

use the best information available to 

determine the gas composition while 

maintaining the option for reporters to 

use 40 CFR 98.233(u)(2) if they do not 

have other stream-specific information. 

In addition to improving the accuracy of 

the emissions calculated and therefore 

the quality of data collected, consistent 

with section II.A.2 of this preamble, this 

proposed amendment is expected to 

provide additional flexibility for 

reporters, consistent with section II.B.2 

of this preamble. 

Second, GPA Midstream indicated 

that the existing provisions of 40 CFR 

98.233(z)(1)(ii) are unclear and that 

some member companies have been 

interpreting those provisions to mean 

that reporters with combustion sources 

at onshore petroleum and natural gas 

production facilities, at onshore 

petroleum and natural gas gathering and 

boosting facilities, and at natural gas 

distribution facilities must use the 

calculation methodologies in subpart W 

rather than subpart C (even given the 

provisions in 40 CFR 98.233(z)(1) that 

reference subpart C for certain fuels).101

The existing provisions of 40 CFR 

98.233(z)(1)(ii) are intended to refer 

only to the reporting requirements and 

are not intended to define which 

calculation methodologies can be used. 

In the current rule, the provisions in the 

40 CFR 98.233(z)(1) introductory text 

define which calculation methodologies 

can be used, and 40 CFR 98.233(z)(1)(ii) 

simply indicates that all reporters with 

combustion sources at onshore 

petroleum and natural gas production 

facilities, at onshore petroleum and 

natural gas gathering and boosting 

facilities, and at natural gas distribution 

facilities must report those emissions in 

the e-GGRT system under subpart W 

rather under subpart C. As part of the 

amendments described in this section, 

consistent with section II.A.5 of this 

preamble, 40 CFR 98.233(z)(1)(ii) is 

proposed to be moved to 40 CFR 

98.233(z)(4), and we are proposing 

wording changes to be clear that this 

paragraph refers only to reporting. We 

are also proposing to add a reference to 

this new paragraph 40 CFR 98.233(z)(4) 

in both 40 CFR 98.233(z)(1)(ii) and 

98.233(z)(2)(ii) (as proposed to be 

amended). 

o. Leak Detection and Measurement 

Methods 

Acoustic leak detection. For emission 

source types for which measurements 

are required, subpart W specifies the 

methods that may be used to make those 

measurements in 40 CFR 98.234(a). To 

improve the quality of the data when an 

acoustic leak detection device is used, 

consistent with section II.A.2 of this 

preamble, we are proposing two 

revisions to the acoustic measurement 

requirements in 40 CFR 98.234(a)(5). 

First, for stethoscope type acoustic leak 

detection devices (i.e., those designed to 

detect through-valve leakage when put 

in contact with the valve body and that 

provide an audible leak signal but do 

not calculate a leak rate), we are 

proposing that a leak is detected if an 

audible leak signal is observed or 

registered by the device. Second, we are 

proposing that if a leak is detected using 

a stethoscope type device, then that leak 

must be measured using one of the 

quantification methods specified in 40 

CFR 98.234(b) through (d) and that leak 

measurement must be reported 

regardless of the volumetric flow rate 

measured. These proposed revisions 

would improve the accuracy of 

emissions reported for compressors and 

transmission tanks when an acoustic 

leak detection device is used. 

High volume samplers. We are 

proposing two revisions to the high 

volume sampler methods to improve the 

quality of the data when high volume 

samplers are used for flow 

measurements, consistent with section 

II.A.2 of this preamble. First, we are 

proposing to add detail to 40 CFR 

98.234(d)(3) to clarify the calculation 

methods associated with high volume 

sampler measurements. Generally, high 

volume samplers measure methane 

flow, not whole gas flow. However, the 

current calculation methods in 40 CFR 

98.234(d)(3) treat the measurement as a 

whole gas measurement. Therefore, we 

are clarifying the calculation methods 

needed if the high volume sampler 

outputs methane flow in either a mass 

flow or volumetric flow basis. 

Specifically, we are proposing methods 

to determine natural gas (whole gas) 

flows based on measured methane 

flows. 

Second, we are proposing to add a 

paragraph at 40 CFR 98.234(d)(5) to 

clarify how to assess the capacity limits 

of a high volume sampler. Currently, 40 

CFR 98.234(d) simply states to ‘‘Use a 

high volume sampler to measure 

emissions within the capacity of the 

instrument’’; there is no other 

information provided to clarify what 

‘‘within the capacity of the instrument’’ 

means or how it is determined. We 

understand that there are different 

manufacturers, but most common high 

volume samplers report maximum 

sampling rates of 10 to 11 cubic feet per 

minute (cfm) and maximum methane 

flow quantitation limits of 6 to 8 cfm. 

Based on our review of reported high 

volume sampler measurements, we 

found that 2 to 5 percent of high volume 

sampler measurements for all types of 

compressor sources (for both centrifugal 

and reciprocating compressors) are 

likely at or beyond the expected 

capacity limits of the high volume 

sampler instrument. Considering actual 

sampling rates, gas collection 

efficiencies near the sampling rates, and 

reported methane quantitation limits 

relative to maximum sampling rates, we 

determined that whole gas flow rates 

exceeding 70 percent of the device’s 

maximum rated sampling rate is an 

indication that the device will not 

accurately quantify the volumetric 

emissions, which we deem to exceed 

the capacity of the device. Therefore, we 

are proposing to specify that methane 

flows above the manufacturer’s methane 

flow quantitation limit or total 

volumetric flows exceeding 70 percent 

of the manufacturer’s maximum 

sampling rate indicate that the flow is 

beyond the capacity of the instrument 

and that flow meters or calibrated bags 

must be used to quantify the flow rate. 

For more information on our review, see 

the subpart W TSD, available in the 


jspears on DSK121TN23PROD with PROPOSALS2
36986 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

102Letter from Matt Hite, GPA Midstream 

Association, to Mark de Figueiredo, U.S. EPA, Re: 

Additional Information on Suggested Part 98, 

Subpart W Rule Revisions to Reduce Burden. 

September 13, 2019. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

docket for this rulemaking (Docket Id. 

No EPA–HQ–OAR–2019–0424). 

p. Onshore Petroleum and Natural Gas 

Gathering and Boosting Compressor 

Stations 

The EPA received feedback from GPA 

Midstream that a count of compressor 

stations per Onshore Petroleum and 

Natural Gas Gathering and Boosting 

facility would provide the EPA with 

improved data on the number and type 

of equipment at gathering and boosting 

stations, which could help to better 

inform future rulemakings.102 In 

addition, the EPA could use information 

on the count of compressor stations to 

improve the process of verifying annual 

reports to the GHGRP. As an example, 

a facility with high emissions for a 

particular source type compared to 

other facilities in the same basin might 

currently be identified as a potential 

outlier. However, if the report also 

indicated that the facility has a large 

number of compressor stations 

compared to other facilities, the EPA 

could use that information during report 

verification to confirm the high 

emissions without needing to contact 

the facility owner or operator. 

Therefore, the EPA is proposing to add 

a requirement in 40 CFR 

98.236(aa)(10)(v) to report the count of 

compressor stations for facilities in the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting industry 

segment, consistent with section II.A.4 

of this preamble. Additionally, the 

count of compressor stations per facility 

would allow for refinements to the 

activity data used by the U.S. GHG 

Inventory. In particular, the calculated 

national-level compressor station 

activity data used by the U.S. GHG 

Inventory could be informed by 

reported compressor station counts for 

Onshore Petroleum and Natural Gas 

Gathering and Boosting facilities subject 

to subpart W, which improves the U.S. 

GHG Inventory estimate of total national 

emissions. The EPA is also proposing a 

definition of ‘‘compressor station’’ in 40 

CFR 98.238 to be used for the purposes 

of this reporting requirement to reduce 

any potential reporter confusion. 

Based on the definition of Onshore 

Petroleum and Natural Gas Gathering 

and Boosting industry segment, this 

industry segment also includes 

‘‘centralized oil production sites.’’ 

These are sites that collect oil from 

multiple well pads but that do not have 

compressors (i.e., are not ‘‘compressor 

stations’’). Therefore, we are proposing 

to add a requirement in 40 CFR 

98.236(aa)(10)(vi) to report the count of 

centralized oil production sites for 

facilities in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segment, consistent with 

section II.A.4 of this preamble. We are 

also proposing to add a definition of 

‘‘centralized oil production site’’ in 40 

CFR 98.238 to be used for the purposes 

of this reporting requirement. These 

proposed additional data elements 

would enhance the overall quality of the 

data collected under the GHGRP. 

q. Onshore Natural Gas Transmission 

Pipeline Throughput Information 

Similar to Natural Gas Distribution 

facilities, Onshore Natural Gas 

Transmission Pipeline facilities are 

currently required to report five 

throughput volumes under subpart W, 

as specified in 40 CFR 98.236(aa)(11). 

These five data reporting elements 

include: the quantity of natural gas 

received at all custody transfer stations; 

the quantity of natural gas withdrawn 

from in-system storage; the quantity of 

gas added to in-system storage; the 

quantity of gas transferred to third 

parties; and the quantity of gas 

consumed by the transmission pipeline 

facility for operational purposes. As 

noted in section III.J.2.g of this 

preamble, the EPA has received 

stakeholder comments on the reporting 

elements for Natural Gas Distribution 

facilities, including questions submitted 

to the GHGRP Help Desk, regarding the 

term ‘‘in-system storage.’’ Although the 

questions were specific to Natural Gas 

Distribution facilities, the term ‘‘insystem storage’’ is also included in the 

throughput reporting elements for 

Onshore Natural Gas Transmission 

Pipeline facilities at 40 CFR 

98.236(aa)(11)(ii) and (iii). After 

consideration of the stakeholder 

comments, the EPA is proposing to 

clarify the term ‘‘in-system.’’ 

Specifically, we are proposing to amend 

40 CFR 98.236(aa)(11)(ii) and (iii) to 

clarify that ‘‘in-system’’ withdrawals/ 

additions of natural gas from storage are 

specifically referring to Underground 

Natural Gas Storage and LNG Storage 

facilities that are owned and operated 

by the onshore natural gas transmission 

pipeline owner or operator that do not 

report under subpart W as direct 

emitters themselves. These amendments 

are expected to improve data quality 

consistent with section II.A.5 of this 

preamble. 

2. Proposed Revisions to Streamline and 

Improve Implementation for Subpart W 

As further described in section II.B of 

this preamble, we are also proposing 

amendments to remove, reduce, or 

simplify requirements that would 

streamline and improve implementation 

while maintaining the quality of the 

data collected under part 98. To 

determine which reporting requirements 

and data elements of subpart W to 

propose amending, the EPA reviewed 

correspondence with reporters during 

the annual verification of GHGRP data, 

questions submitted to the GHGRP Help 

Desk and the responses provided, and 

the specific regulatory language of 

subpart W. As a result of that process, 

the EPA is proposing to eliminate, 

clarify, or otherwise amend select 

calculation methodologies and reporting 

requirements as described in this 

section. Consistent with section II.B.2 of 

this preamble, some of the proposed 

amendments would add monitoring or 

reporting flexibility for certain 

calculation methodologies. Other 

proposed revisions would remove 

reporting requirements that are 

redundant with data already reported to 

the EPA or no longer being used at this 

time, as further described in section 

II.B.3 of this preamble. 

a. Dehydrator Vents 

Removal of requirements for desiccant 

dehydrators. Subpart W currently 

requires reporting of desiccant 

dehydrators as a subcategory of 

dehydrator vents. Based on the data 

reported to date, the emissions from 

these sources are less than 0.1 percent 

of total reported emissions from 

dehydrator vents (in RY2020, desiccant 

dehydrators contributed 760 mtCO2e of 

the total 3.35 million mtCO2e from all 

dehydrator vent emissions). In addition, 

it appears that a significant percentage 

of the emissions reported to date may be 

from molecular sieve dehydrators; 

however, we never intended to require 

reporting of emissions from such units, 

and based on the definition of 

‘‘dehydrator’’ in 40 CFR 98.6, we do not 

read the rule to require such reporting. 

In RY2015 through RY2020, about 60 

percent of the facilities that reported 

counts of desiccant dehydrators also 

reported emissions of 0 mtCO2e (516 out 

of 897 reporters), and more than onequarter of the reported desiccant 

dehydrators were at facilities that 

reported 0 emissions from desiccant 

dehydrators (1,888 out of 7,139 units). 

Furthermore, facilities that report 

emissions from desiccant dehydrators in 

a given year may not have depressurized 

every one of their desiccant dehydrators 


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Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 36987 

103We are also proposing to move the 

specifications for calculating mass emissions from 

volumetric emissions for glycol dehydrators with an 

annual average of daily natural gas throughput that 

is less than 0.4 MMscf per day from 40 CFR 

98.233(e)(4) to 40 CFR 98.233(e)(2), which would 

consolidate the requirements for those dehydrators. 

in that year, but this cannot be 

determined from the reported data 

because emissions are reported at the 

facility level instead of per dehydrator. 

This pattern of emissions reporting is 

consistent with the expected results for 

molecular sieve dehydrators because 

such units typically are opened 

(depressurized) only once every few 

years. Thus, a significant percentage of 

the reported emissions from desiccant 

dehydrators may be from units that are 

not subject to reporting, meaning that 

the actual emissions from desiccant 

dehydrators would be less than the 

reported 0.1 percent of the total 

dehydrator emissions. Therefore, we are 

proposing to remove requirements for 

desiccant dehydrators from 40 CFR 

98.233(e)(3) and (4) and 40 CFR 

98.236(e)(3) of subpart W, consistent 

with section II.B.2 and II.B.3 of this 

preamble.103 As a corollary to the 

proposed removal of the desiccant 

dehydrator requirements, we are also 

proposing to remove the definition of 

‘‘desiccant’’ and to revise the definition 

of ‘‘dehydrator’’ in 40 CFR 98.6, as 

discussed in section III.A of this 

preamble. 

As an alternative to removing the 

requirements for all desiccant 

dehydrators, we considered revising 40 

CFR 98.233(e)(3) to clarify that only 

devices with desiccant that absorb water 

(as opposed to those containing 

materials that adsorb water) are subject 

to the GHGRP. That change would be 

consistent with the original intent, as 

evidenced by the definitions of 

‘‘desiccant’’ and ‘‘dehydrator’’ in 40 

CFR 98.6, and it would clarify that 

molecular sieve units (which contain 

material that adsorbs water) are not 

subject to subpart W. That change also 

would reduce the number of reporters. 

However, we are not proposing that 

option because the reported emissions 

would be extremely small relative to 

other dehydrator emissions. We request 

comment on other advantages and 

disadvantages of this option relative to 

the proposed plan of deleting 

requirements for desiccant dehydrators 

and whether commenters think there are 

potential benefits of this option that 

outweigh potential drawbacks. 

Although this proposal would remove 

the desiccant dehydrator requirements 

from subpart W, other requirements in 

subpart W may then apply instead. 

Currently, 40 CFR 98.233(e)(3) and 40 

CFR 98.233(i) specify that desiccant 

dehydrator emissions calculated using 

equation W–6 do not have to be 

calculated separately under the 

blowdown vent stacks provisions in 40 

CFR 98.233(i). However, because we are 

proposing to remove the desiccant 

dehydrator provisions, the EPA is also 

proposing to remove the exception at 

the end of the 40 CFR 98.233(i) 

introductory paragraph. Thus, the 

blowdown provisions in 40 CFR 

98.233(i) would apply, provided that the 

volume of space in a desiccant 

dehydrator that is depressurized to 

atmosphere is greater than 50 cubic feet. 

Similarly, in the absence of desiccant 

dehydrator provisions, if the emissions 

from depressurizing desiccant 

dehydrators are routed to a flare, then 

the emissions would be subject to the 

requirements for flare stack emissions in 

40 CFR 98.233(n). We note that while 

these emissions may still be reported to 

the EPA if the proposal to remove the 

desiccant dehydrator provisions is 

finalized, they would no longer be 

required to be calculated and reported 

separately, which would still streamline 

implementation for reporters. 

Clarification of Count for Glycol 

Dehydrators with Annual Average Daily 

Natural Gas Throughput Less Than 0.4 

MMscf per Day. As noted in section 

III.J.1.d of this preamble, for glycol 

dehydrators with an annual average 

daily natural gas throughput less than 

0.4 MMscf per day, reporters currently 

use population emission factors and 

equation W–5 to calculate volumetric 

CO2 and CH4 emissions per 40 CFR 

98.233(e)(2) and report emissions per 40 

CFR 98.236(e)(2). Under these current 

requirements, the count of glycol 

dehydrators with annual average daily 

natural gas throughput less than 0.4 

MMscf per day could include 

dehydrators with annual average daily 

natural gas throughput of 0 MMscf per 

day (i.e., glycol dehydrators that were 

not operated during the reporting year). 

As a result, some annual reports include 

a nonzero count of dehydrators per 40 

CFR 98.236(e)(2)(i) without any 

corresponding CO2 and CH4 emissions. 

In these cases, it is not clear if the 

reporter did not report emissions 

because emissions are not expected, the 

emissions data were inadvertently 

omitted, or the nonzero count represents 

the total count of all dehydrators with 

annual average daily natural gas 

throughput less than 0.4 MMscf per day, 

including those that were not in use. 

Therefore, the EPA is proposing to 

clarify in 40 CFR 98.233(e)(2) that the 

dehydrators for which emissions are 

calculated should be those with annual 

average daily natural gas throughput 

greater than 0 MMscf per day and less 

than 0.4 MMscf per day (i.e., the count 

should not include dehydrators that did 

not operate during the year). Similarly, 

the EPA is proposing to clarify that the 

count of dehydrators in 40 CFR 

98.236(e)(2)(i) should also be those with 

annual average daily natural gas 

throughput greater than 0 MMscf per 

day and less than 0.4 MMscf per day. 

These amendments are expected to 

streamline and improve 

implementation, consistent with section 

II.B.3 of this preamble. 

b. Blowdown Vent Stacks 

Blowdown equipment types. Subpart 

W currently requires reporting of 

blowdowns either using flow meter 

measurements (40 CFR 98.233(i)(3)) or 

using unique physical volume 

calculations by equipment or event 

types (40 CFR 98.233(i)(2)). When the 

Onshore Natural Gas Transmission 

Pipeline industry segment was added to 

subpart W in 2015, public commenters 

indicated that the existing equipment or 

event types were not appropriate for the 

new segment, so the EPA developed 

new equipment or event types that 

apply only for the Onshore Natural Gas 

Transmission Pipeline industry segment 

(80 FR 64275, October 22, 2015). The 

new equipment or event types were 

added to the introductory paragraph of 

40 CFR 98.233(i)(2), where the existing 

equipment or event types were already 

located, resulting in a complex 

introductory paragraph. Also, both the 

third sentence and last sentence in 40 

CFR 98.233(i)(2) currently read as 

follows: ‘‘If a blowdown event resulted 

in emissions from multiple equipment 

types and the emissions cannot be 

apportioned to the different equipment 

types, then categorize the blowdown 

event as the equipment type that 

represented the largest portion of the 

emissions for the blowdown event.’’ 

According to this provision, when a 

blowdown event consists of emissions 

from two or more equipment types, the 

emissions must be apportioned to each 

applicable equipment type, unless such 

apportionment is not possible. 

The EPA is proposing to move the 

listings of event types and the 

apportioning provisions to a new 40 

CFR 98.233(i)(2)(iv) so that the 

introductory paragraph in 40 CFR 

98.233(i)(2) would be more concise and 

provide clearer information regarding 

which requirements are applicable for 

each blowdown. Proposed 40 CFR 

98.233(i)(2)(iv) includes separate 

paragraphs for each set of equipment 

and event type categories and would 

also provide clearer information 


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regarding the applicable requirements 

for each industry segment. 

Blowdown Temperature and Pressure. 

In the 2015 amendments to subpart W 

(80 FR 64262, October 22, 2015), the 

EPA added the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segment and the Onshore 

Natural Gas Transmission Pipeline 

industry segment and specified that 

both industry segments are required to 

report emissions from blowdown vents. 

Stakeholders representing the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting industry segment provided 

comments on the proposed rule stating 

that the proposed definition of facility 

would make equipment geographically 

dispersed, and blowdowns may occur 

without personnel on-site or nearby, 

which would make it difficult to collect 

the information needed to calculate 

emissions from each blowdown (80 FR 

64271, October 22, 2015). As a result of 

those comments, the EPA also specified 

in the final amendments to equation W– 

14A that for emergency blowdowns at 

onshore petroleum and natural gas 

gathering and boosting facilities, 

engineering estimates based on best 

available information may be used to 

determine the actual temperature and 

actual pressure. 

Since that time, the EPA has received 

questions through the GHGRP Help 

Desk indicating that facilities in the 

Onshore Natural Gas Transmission 

Pipeline industry segment also have 

unmanned blowdown vents. Given that 

a ‘‘facility with respect to the onshore 

natural gas transmission pipeline 

segment’’ is the total mileage of natural 

gas transmission pipelines owned and 

operated by an onshore natural gas 

transmission pipeline owner or 

operator, all of the blowdown vents at 

that facility would be outside the 

fenceline of a transmission compression 

station and would be geographically 

dispersed. The EPA considers it 

reasonable to assume that those 

blowdown vents may also be 

unmanned. Therefore, we are proposing 

to extend the provisions in equation W– 

14A of 40 CFR 98.233(i)(2)(i) that allow 

use of engineering estimates based on 

best available information to determine 

the temperature and pressure of an 

emergency blowdown to the Onshore 

Natural Gas Transmission Pipeline 

segment, which would align the 

requirements for the two geographically 

dispersed industry segments (Onshore 

Natural Gas Transmission Pipeline and 

Onshore Petroleum and Natural Gas 

Gathering and Boosting) and increase 

flexibility for Onshore Natural Gas 

Transmission Pipeline reporters, 

consistent with section II.B.2 of this 

preamble. 

In addition, similar provisions to 

allow use of engineering estimates based 

on best available information to 

determine the temperature and pressure 

of an emergency blowdown were not 

added to equation W–14B of 40 CFR 

98.233(i)(2)(i) in 2015 (80 FR 64262, 

October 22, 2015). We have reviewed 

this equation and have determined that 

this omission was inadvertent. 

Therefore, we are proposing to add 

provisions to equation W–14B to allow 

use of engineering estimates to 

determine the temperature and pressure 

of an emergency blowdown for both the 

Onshore Natural Gas Transmission 

Pipeline and Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segments, consistent with 

equation W–14A. 

c. Atmospheric Storage Tanks 

Calculation methods 1 and 2 

reporting. For facilities reporting 

atmospheric storage tank emissions 

calculated using Calculation Method 1 

or Calculation Method 2, 40 CFR 

98.236(j)(1) requires reporting of counts 

of the total number of atmospheric 

storage tanks within the sub-basin or 

county, the number of atmospheric 

storage tanks that are controlled by a 

vapor recovery system, the number of 

atmospheric storage tanks that are 

controlled by a flare, and the number of 

atmospheric storage tanks that are not 

controlled by either a vapor recovery 

system or a flare. As atmospheric 

storage tanks are typically controlled by 

both a vapor recovery system and a 

flare, these counts allow for overlap and 

cause confusion among reporters. 

Additionally, atmospheric storage tanks 

may be included in multiple categories 

of counts if the facility elects to add an 

emissions control partway through the 

reporting year. 

Therefore, the EPA is proposing to 

reorganize the reporting requirements in 

40 CFR 98.236(j)(1) to reduce overlap 

between several of the current data 

elements that are reported by control 

methodology. Specifically, the EPA is 

proposing to collect only the total 

number of tanks within the sub-basin or 

county, the count of atmospheric tanks 

that routed emissions to vapor recovery 

and/or flares at any point during the 

reporting year, and the count of 

atmospheric tanks that vented gas 

directly to the atmosphere and did not 

control emissions using a vapor 

recovery system or flares at any point 

during the reporting year. 

For consistency with the revisions to 

the atmospheric storage tank count data 

elements, the EPA is proposing to 

require separate reporting of emissions 

for tanks that did not control emissions 

using a vapor recovery system or flares 

at any point during the reporting year 

and for tanks that routed emissions to 

vapor recovery and/or flares at any 

point during the reporting year. For 

tanks that do not control emissions 

using a vapor recovery system or flares 

at any point during the reporting year, 

facilities would report CO2 and CH4

emissions resulting from venting gas 

directly to the atmosphere. For tanks 

that rout emissions to vapor recovery 

and/or flares at any point during the 

reporting year, facilities would report 

CO2, CH4, and N2O emissions from 

flares and the total mass of CO2 and CH4

that was recovered using a vapor 

recovery system in addition to the CO2

and CH4 emissions resulting from 

venting gas directly to the atmosphere. 

With this reorganization of the 

emissions reporting requirements for 

atmospheric storage tanks, the EPA 

expects to streamline reporting and 

reduce redundancy between data 

elements, consistent with section II.B.3 

of this preamble. 

Additionally, the EPA is proposing to 

remove the requirement to report an 

estimate of the number of atmospheric 

storage tanks that are not on well-pads 

and that are receiving the facility’s oil 

(40 CFR 98.236(j)(1)(xi)), consistent with 

section II.B.3 of this preamble. This 

reporting requirement is redundant 

because all Onshore Petroleum and 

Natural Gas Production facilities 

reporting atmospheric storage tank 

emissions calculated using Calculation 

Method 1 or Calculation Method 2 must 

also report the total number of 

atmospheric tanks in the sub-basin per 

40 CFR 98.236(j)(1)(x). 

Calculation method 3 reporting. For 

hydrocarbon liquids flowing to gasliquid separators or non-separator 

equipment or directly to atmospheric 

storage tanks with throughput less than 

10 barrels per day, reporters follow the 

Calculation Method 3 methodology 

specified in 40 CFR 98.233(j)(3) and 

equation W–15. Equation W–15 uses 

population emission factors and the 

count of applicable separators, wells, or 

non-separator equipment to determine 

the annual total volumetric GHG 

emissions at standard conditions. The 

associated reporting requirements in 40 

CFR 98.236(j)(2)(i)(E) through (F) 

require reporters to delineate the count 

used in equation W–15 into the number 

of wells with gas-liquid separators in 

the basin and those without gas-liquid 

separators. The EPA has received 

feedback through correspondence with 

reporters via e-GGRT that these 

reporting requirements are unclear. 


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After consideration of this feedback, the 

EPA has made a preliminary 

determination that these reporting 

requirements are not consistent with the 

language used in the definition of the 

‘‘Count’’ variable in equation W–15, nor 

are they inclusive of all equipment to be 

included in the count. 

Therefore, the EPA is proposing to 

revise 40 CFR 98.236(j)(2)(i)(E) to 

completely align the requirement with 

the total ‘‘Count’’ input variable in 

equation W–15. The EPA proposes to 

amend the language in 40 CFR 

98.236(j)(2)(i)(E) to request the total 

number of separators, wells, or nonseparator equipment in the basin used 

to calculate Calculation Method 3 

storage tank emissions. The current 

language in 40 CFR 98.236(j)(2)(i)(E) 

requests the number of wells with gasliquid separators in the basin, which is 

only a subset of the equipment included 

in the ‘‘Count’’ variable. Further, the 

EPA is proposing to remove the 

reporting requirement in 40 CFR 

98.236(j)(2)(i)(F), which requires 

reporting of the number of wells 

without gas-liquid separators in the 

basin. Both of the current data elements 

in 40 CFR 98.236(j)(2)(i)(E) and 40 CFR 

98.236(j)(2)(i)(F) have been determined 

to be no longer as useful for present 

program or policy purposes, as they do 

not correlate with the calculated 

Calculation Method 3 atmospheric tank 

emissions. These changes would 

streamline the requirements for all 

facilities reporting atmospheric storage 

tanks emissions using Calculation 

Method 3. Consistent with section II.B.3 

of this preamble, reporters would no 

longer be required to determine two 

separate counts that may not be 

representative of the inputs used in 

equation W–15. 

In addition, the provisions in 40 CFR 

98.236(j)(2)(ii) and (iii) require facilities 

to separately report Calculation Method 

3 emissions from atmospheric storage 

tanks that did not control emissions 

with flares and those that controlled 

emissions with flares, respectively. 

Using the calculation procedures 

provided in 40 CFR 98.233(j)(3) through 

(5), when a facility adds a flare control 

to an atmospheric storage tank in the 

middle of a reporting year, facilities are 

required to separately calculate 

emissions that are not flared from 

emissions that are flared from that tank, 

sum these emissions values, and report 

all emissions from the tank as part of the 

sub-basin or county flared tanks total 

per the requirements of 40 CFR 

98.236(j)(2)(iii). In an effort to 

streamline and improve implementation 

consistent with section II.B.2 of this 

preamble, the EPA is proposing to 

clarify that for storage tanks using 

Calculation Method 3, reporters would 

calculate either flared or vented 

emissions for a tank, but not both. 

Specifically, the EPA is proposing to 

add language in 40 CFR 98.233(j)(5) that 

specifies that if the flare captured flash 

gas from at least half of the annual 

hydrocarbon liquids received by the 

tank for which emissions were 

calculated using Calculation Method 3, 

flared emissions would be calculated 

according to 40 CFR 98.233(j)(5) (i.e., as 

if all flash gas generated from a tank 

during the entire reporting year is sent 

to a flare). The EPA is also proposing to 

amend 40 CFR 98.236(j)(2)(iii) to specify 

that the reporting requirements in that 

section only apply to tanks whose 

emissions were calculated using 

Calculation Method 3 that used flares to 

control emissions from at least half the 

annual hydrocarbon liquids received. 

The EPA is proposing a corresponding 

change to 40 CFR 98.236(j)(2)(ii), which 

would require reporting of the 

Calculation Method 3 emissions from 

the remaining atmospheric storage tanks 

that either used flares to control 

emissions from less than half the annual 

hydrocarbon liquids received or did not 

control any emissions with a flare. The 

emissions from these remaining 

atmospheric storage tanks would be 

calculated as venting directly to the 

atmosphere for the entire year (i.e., 

emissions from tanks that flared for less 

than half of the year would not be 

calculated using the flare procedures 

provided in 40 CFR 98.233(j)(5)). 

d. Flared Transmission Storage Tank 

Vent Emissions 

Reporters in the transmission 

compression industry segment currently 

are required to report flared emissions 

specific to their transmission storage 

tanks separately from other flare stack 

emissions. In the years RY2015 through 

RY2020, between one and six facilities 

per year reported having a transmission 

tank vent stack routed to a flare, and 

each of these facilities reported no leaks. 

As a result, the reported flared 

emissions from transmission storage 

tank vent stacks in each of the last 6 

years have been 0 metric tons of CO2, 

CH4, and N2O. Based on these results, 

the EPA has made a preliminary 

determination that continued reporting 

of source-specific flared emissions from 

transmission tanks would not likely 

provide new insights or knowledge of 

the industry sector, emissions, or trends. 

Therefore, consistent with section II.B.3 

of this preamble, the EPA is proposing 

that transmission tanks be classified as 

a miscellaneous flared source such that 

any flared emissions from the tanks in 

the future would be reported 

collectively with flared emissions from 

all miscellaneous flared sources as 

specified in 40 CFR 98.236(n)(1). The 

EPA is proposing to retain the current 

requirements in 40 CFR 98.233(k)(1) and 

(2) to monitor the tank vent stack 

annually for leaks and to quantify the 

leak rate if a leak is detected. As an 

alternative to these source-specific 

requirements, a reporter also would be 

allowed to continuously measure either 

total flow from the transmission tank 

vent stack or the comingled total flow 

into the flare, consistent with the 

existing requirement in 40 CFR 

98.233(n)(1). Flow data determined by 

either of these methods would still be 

needed to calculate total flared 

emissions from the miscellaneous flared 

sources. Reporting requirements would 

remain essentially the same except that 

flared mass emissions would no longer 

be reported under 40 CFR 98.236(k)(3). 

Note that if we decide not to finalize the 

proposed changes described in this 

section after considering public 

comment, then we alternatively propose 

that we would finalize flare activity data 

reporting requirements for flared 

emissions from transmission storage 

tank vent stacks consistent with the 

activity data reporting for other source 

types that have source-specific flared 

emissions reporting requirements as 

described in the ‘‘Calculation 

Methodology for Flared Emissions’’ 

subsection in section III.J.1.i of this 

preamble. The proposed rule language 

under this alternative would be added 

to 40 CFR 98.233(k)(5), and it would be 

similar to proposed language for other 

flared sources (e.g., well testing in 40 

CFR 98.233(l)(6) and associated gas 

flaring in 40 CFR 98.233(m)(5)). One 

difference is that an option to 

continuously measure combined 

streams into a flare would not be 

allowed for transmission tanks because 

it would not be possible to tell if there 

were any scrubber dump valve leaks if 

only a combined emissions stream is 

measured. We request comment on the 

advantages and disadvantages of both 

approaches we are considering relative 

to the current requirements. 

e. Compressors 

As noted in section III.J.1.j of this 

preamble, reporting requirements for 

compressors in the Onshore Natural Gas 

Processing, Onshore Natural Gas 

Transmission Compression, 

Underground Natural Gas Storage, LNG 

Storage, and LNG Import and Export 

Equipment industry segments include 

requirements to conduct ‘‘as found’’ 

measurements for the compressor modesource combination in which the 


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36990 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

104Letter from GPA Midstream Association to 

Mark de Figueiredo, U.S. EPA, providing 

information in response to EPA questions during 

the meeting on March 23, 2016. May 18, 2016. 

Available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

compressor is found. In addition, if a 

given compressor was not measured in 

not-operating-depressurized-mode 

during the ‘‘as found’’ measurements for 

three consecutive years, a measurement 

in not-operating-depressurized-mode is 

currently required to be taken during 

the next planned scheduled shutdown 

of the compressor, per 40 CFR 

98.233(o)(1)(i)(C) and (p)(1)(i)(D). This 

provision requires reporters to schedule 

an extra ‘‘as found’’ measurement to 

make this required measurement if the 

compressor was not found in this mode 

when the regularly scheduled ‘‘as 

found’’ measurements were taken. 

We are proposing to eliminate this 

requirement to conduct a measurement 

in not-operating-depressurized-mode at 

least once every three years, consistent 

with section II.B.2 of this preamble. We 

originally included this requirement in 

subpart W in order to obtain a sufficient 

amount of data for this mode (75 FR 

74458, November 30, 2010). However, 

based on data collected under subpart 

W thus far, many compressors are in 

not-operating-depressurized-mode for 

30 percent of the time or more. As such, 

the extra measurements are 

unnecessary, and we are proposing to 

eliminate this requirement and make the 

annual ‘‘as found’’ measurements true 

‘‘as found’’ measurements. We are also 

proposing to remove the reporting 

requirement to indicate if the 

compressor had a scheduled 

depressurized shutdown during the 

reporting year (40 CFR 98.236(o)(1)(xiv) 

and 40 CFR 98.236(p)(1)(xiv)) because 

that information is only collected to 

verify compliance with the requirement 

to conduct a measurement in notoperating-depressurized-mode at least 

once every three years. 

In addition, centrifugal and 

reciprocating compressors are the only 

sources for which capture for fuel use 

and thermal oxidizers are specifically 

listed as dispositions for emissions that 

would otherwise be vented. The EPA’s 

intent with the provisions is to 

differentiate flares, which are 

combustion devices that combust waste 

gases without energy recovery (per 40 

CFR 98.238), from combustion devices 

with energy recovery, including for fuel 

use. However, some thermal oxidizers 

combust waste gases without energy 

recovery and therefore may instead meet 

the subpart W definition of flare. To 

avoid confusion, and to clarify that the 

EPA’s intent is generally to treat 

emissions routed to flares and 

combustion devices other flares 

consistently, we are proposing to 

remove the references to fuel use and to 

thermal oxidizers in 40 CFR 98.233(o) 

and (p) and 40 CFR 98.236(o) and (p). 

Instead, we are proposing to define 

‘‘routed to combustion’’ in 40 CFR 

98.238 to specify the types of non-flare 

combustion equipment for which 

reporters would be expected to calculate 

emissions. In particular, for the Onshore 

Petroleum and Natural Gas Production, 

Onshore Petroleum and Natural Gas 

Gathering and Boosting, and Natural 

Gas Distribution industry segments, 

‘‘routed to combustion’’ means the 

combustion equipment specified in 40 

CFR 98.232(c)(22), (i)(7), and (j)(12), 

respectively (i.e., the combustion 

equipment for which emissions must be 

calculated per 40 CFR 98.233(z)). For all 

other industry segments, ‘‘routed to 

combustion’’ means the stationary 

combustion sources subject to subpart 

C. The proposed definition of ‘‘routed to 

combustion’’ would apply for all 

subpart W emission sources for which 

that term appears (e.g., natural gas 

driven pneumatic pumps). 

Finally, we are proposing to remove 

some data elements that are redundant 

between 40 CFR 98.236(o)(1) and (2) for 

centrifugal compressors and between 40 

CFR 98.236(p)(1) and (2) for 

reciprocating compressors. Specifically, 

40 CFR 98.236(o)(1)(vi) and 40 CFR 

98.236(p)(1)(vi) require reporters to 

indicate which individual compressors 

are part of a manifolded group of 

compressor sources, and 40 CFR 

98.236(o)(1)(vii) through (ix) and 40 

CFR 98.236(p)(1)(vii) through (ix) 

require reporters to indicate whether 

individual compressors have 

compressor sources routed to flares, 

vapor recovery, or combustion. 

However, 40 CFR 98.236(o)(2)(ii)(A) and 

40 CFR 98.236(p)(2)(ii)(A) require the 

same information for each compressor 

leak or vent rather than by compressor. 

The information collected for each leak 

or vent is more detailed and is the 

information used for emissions 

calculations. Therefore, the EPA is 

proposing to remove the redundant 

reporting requirements in 40 CFR 

98.236(o)(1)(vi) through (ix) and 40 CFR 

98.236(p)(1)(vi) through (ix), consistent 

with section II.B.3 of this preamble. 

f. Combustion 

Subpart W refers reporters in the 

Onshore Petroleum and Natural Gas 

Production, Onshore Petroleum and 

Natural Gas Gathering and Boosting, 

and Natural Gas Distribution industry 

segments to the calculation 

methodologies in subpart C to 

determine combustion emissions for 

certain fuels. Specifically, 40 CFR 

98.233(z)(1) specifies that reporters may 

use any tier of subpart C if the fuel 

combusted is listed in Table C–1; the 

paragraph further specifies that the 

subpart C methodologies may only be 

used for fuel meeting the definition of 

‘‘natural gas’’ in 40 CFR 98.238 if it is 

also of pipeline quality specification 

and has a minimum HHV of 950 Btu per 

standard cubic foot (Btu/scf). If the fuel 

is natural gas that does not meet these 

criteria, field gas, process vent gas, or a 

blend containing field gas or process 

vent gas, 40 CFR 98.233(z)(1) specifies 

that the procedures in 40 CFR 

98.233(z)(2) should be used to calculate 

combustion emissions. Stakeholders 

(e.g., GPA Midstream) have identified 

several concerns with these 

requirements. In general, they have 

stated that the ability to use subpart C 

calculation methodologies is unclear 

and too restrictive. We are proposing 

several amendments to these provisions 

to address these concerns and increase 

the flexibility of the calculation 

methods, consistent with section II.B.2 

of this preamble. 

First, GPA Midstream has indicated 

that it is not clear whether field gas that 

is of pipeline quality meets the criteria 

to use the subpart C methodologies 

under 40 CFR 98.233(z)(1),104 and ‘‘field 

gas’’ is not defined within subpart W or 

subpart A (General Provisions). The 

terms ‘‘field gas’’ and ‘‘field quality’’ are 

frequently used interchangeably by the 

industry, but the EPA also recognizes 

that some streams in the Onshore 

Petroleum and Natural Gas Gathering 

and Boosting industry segment that 

industry would generally call ‘‘field 

gas’’ can be natural gas (as defined in 40 

CFR 98.238) of pipeline quality with a 

minimum HHV of 950 Btu/scf. GPA 

Midstream stated that the procedures in 

40 CFR 98.233(z)(2) are more 

burdensome than the subpart C 

methodologies and asked that the EPA 

clarify that ‘‘field gas’’ streams of 

pipeline quality can use the subpart C 

methodologies. After review of these 

comments, the EPA is proposing to 

revise 40 CFR 98.233(z)(1) to remove the 

references to field gas and process vent 

gas and include only the characteristics 

for the fuels that can use subpart C 

methodologies. The EPA’s intent is to 

clarify that a stream colloquially 

referred to as ‘‘field gas’’ that otherwise 

meets the three criteria to use the 

subpart C methodologies for combustion 

emissions (i.e., (1) meets the definition 

of ‘‘natural gas’’ in 40 CFR 98.238; (2) 

is of pipeline quality specification; and 

(3) has a minimum HHV of 950 Btu/scf) 

may use subpart C methodologies. The 


jspears on DSK121TN23PROD with PROPOSALS2
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105See Letter from GPA Midstream Association to 

Mark de Figueiredo, U.S. EPA, providing 

information in response to EPA questions during 

the meeting on March 23, 2016. May 18, 2016. See 

also Letter from Matt Hite, GPA Midstream 

Association, to Mark de Figueiredo, U.S. EPA, Re: 

Additional Information on Suggested Part 98, 

Subpart W Rule Revisions to Reduce Burden. 

September 13, 2019. Both letters are available in the 

docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

106See Docket Id. Nos. EPA–HQ–OA–2017–0190– 

46726, EPA–HQ–OA–2017–0190–1958, EPA–HQ– 

OA–2017–0190–2066 available in Compilation of 

Comments Related to the Greenhouse Gas Reporting 

Program submitted to the Department of Commerce 

under Docket ID No. DOC–2017–0001 and the 

Environmental Protection Agency under Docket ID 

No. EPA–HQ–OA–2017–0190 and in the docket for 

this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

EPA is also proposing conforming edits 

to 40 CFR 98.233(z)(2) (proposed to be 

moved to 40 CFR 98.233(z)(3)) for 

consistency. 

Second, reporters have indicated in 

questions submitted to the GHGRP Help 

Desk that the term ‘‘pipeline quality’’ is 

also not defined in subpart W, leading 

to confusion over whether some fuel 

streams meet the criteria to use the 

subpart C calculation methodologies per 

40 CFR 98.233(z)(1). In addition, GPA 

Midstream has opined that the 

emissions calculated using subpart C 

and subpart W calculation 

methodologies are similar for many fuel 

streams that are not natural gas of 

pipeline quality specification with a 

minimum HHV of 950 Btu/scf. 

Therefore, they have suggested that the 

EPA should allow subpart C calculation 

methodologies to be used for a wider 

variety of fuels (if not all fuels in the 

segments that report combustion 

emissions under subpart W).105

We have reviewed the analysis in 

GPA Midstream’s May 18, 2016 letter 

and conducted our own analysis of 

additional hypothetical fuel 

compositions. In general, we observed 

that the agreement of emissions as 

calculated using subpart C calculation 

methodologies for natural gas and using 

subpart W calculation methodologies 

varies based on the composition, with 

the largest differences resulting for fuel 

streams with high CO2 content. We also 

observed that for these fuels, emissions 

calculated using subpart W calculation 

methodologies generally showed better 

agreement with emissions calculated 

using the subpart C calculation 

methodology for natural gas when using 

a site-specific HHV (Tier 2) than with 

emissions calculated using the subpart 

C calculation methodology that uses a 

default HHV (Tier 1). For more 

information on our fuel composition 

analysis and the comparison of 

emissions using various composition 

thresholds, see the subpart W TSD, 

available in the docket for this 

rulemaking (Docket Id. No. EPA–HQ– 

OAR–2019–0424). 

Based on our analysis, we are 

proposing to add numeric composition 

thresholds for natural gas to a new 

paragraph in 40 CFR 98.233(z)(2) that 

define the fuels for which an owner or 

operator may use subpart C 

methodologies. In particular, we are 

proposing that subpart C methodologies 

Tier 2 or higher may be used for fuel 

meeting the definition of ‘‘natural gas’’ 

in 40 CFR 98.238 if it has a minimum 

HHV of 950 Btu/scf, a maximum CO2

content of 1 percent by volume, and a 

minimum CH4 content of 85 percent by 

volume. We are not proposing to amend 

the existing provisions in 40 CFR 

98.233(z)(1) that allow the use of any 

subpart C calculation methodology for 

natural gas of pipeline quality 

specification with a minimum HHV of 

950 Btu/scf (with the clarifications 

noted earlier in this section). We are 

also proposing to move the existing 

provisions for fuels that do not meet the 

specifications to use subpart C 

methodologies from 40 CFR 98.233(z)(2) 

to a new paragraph 40 CFR 98.233(z)(3). 

This proposed amendment would allow 

reporters to use subpart C 

methodologies for a wider variety of fuel 

streams while still ensuring data 

quality. We request comment on the 

natural gas specifications included in 

proposed 40 CFR 98.233(z)(2), including 

the values proposed for the maximum 

CO2 content and minimum CH4 content, 

as well as whether additional 

specification criteria should be included 

(e.g., a maximum HHV). 

Third, we are proposing amendments 

to clarify that emissions may be 

calculated in 40 CFR 98.233(z)(3)(ii) for 

groups of combustion units. The current 

provisions of 40 CFR 98.233(z)(2) 

(proposed to be moved to 40 CFR 

98.233(z)(3)(ii)) could be interpreted to 

specify that emissions must be 

calculated for each individual 

combustion unit. However, because 

combustion emissions and activity data 

are reported as combined totals for each 

type of combustion device and fuel, it 

is not necessary to calculate emissions 

for each individual unit before 

aggregating the total emissions. For 

example, if the volume of fuel 

combusted is determined at a single 

location upstream of several combustion 

units with similar combustion 

efficiencies, emissions may be 

determined for that combined volume of 

fuel (i.e., for that group of combustion 

units). In other words, it is not 

necessary in this case to apportion a 

volume of fuel to each unit, calculate 

emissions separately, and then combine 

them again. If the combustion units 

downstream of this shared measurement 

point are a mix of combustion device 

types, the emissions and the volume of 

fuel would still need to be apportioned 

between those combustion device types 

for reporting purposes; however, 

reporters may elect to perform that 

apportioning either before or after 

emissions are calculated, as appropriate, 

as long as the group of combustion units 

does not include any natural gas-driven 

compressor drivers. If any of the 

combustion units downstream of this 

shared measurement point are natural 

gas-driven compressor drivers, the 

volumes of fuel for those units would 

have to be separated from the total 

before emissions are calculated to 

account for the differences in 

combustion efficiency, as described in 

section III.J.1.n of this preamble. 

g. Onshore Natural Gas Processing and 

Natural Gas Distribution Throughput 

Information 

Onshore Natural Gas Processing 

plants are required to report seven 

facility-level throughput-related items 

under subpart W, as specified in 40 CFR 

98.236(aa)(3). These seven data 

reporting elements include: quantities of 

natural gas received and processed gas 

leaving the gas processing plant, 

cumulative quantities of NGLs received 

and leaving the gas processing plant, the 

average mole fractions of CH4 and CO2

in the natural gas received, and an 

indication of whether the facility 

fractionates NGLs. Natural Gas 

Distribution companies are also 

required to report seven throughput 

volumes under subpart W, as specified 

in 40 CFR 98.236(aa)(9). These seven 

data reporting elements include: the 

quantity of gas received at all custody 

transfer stations; the quantity of natural 

gas withdrawn from in-system storage; 

the quantity of gas added to in-system 

storage; the quantity of gas delivered to 

end users; the quantity of gas transferred 

to third parties; the quantity of gas 

consumed by the LDC for operational 

purposes; and the quantity of gas stolen. 

The EPA has received stakeholder 

comments, including from the American 

Gas Association (AGA),106 related to 

some of these reporting elements. 

Stakeholders have commented that the 

reporting elements included in subpart 

W are redundant with data reported 

elsewhere within the GHGRP, 

specifically under subpart NN 

(Suppliers of Natural Gas and Natural 

Gas Liquids). Subpart NN requires NGL 

fractionators and LDCs to report the 

quantities of natural gas and natural gas 


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107Form EIA–176 is available at the U.S. EIA 

website at https://www.eia.gov/survey/form/eia_

176/form.pdf; the Form EIA–176 Instructions are 

available at https://www.eia.gov/survey/form/eia_

176/instructions.pdf. 

108See page 7 of EPA Response to Public 

Comment Vol. 39 Subpart NN at https://

www.epa.gov/ghgreporting/ghgrp-2009-final-ruleresponse-comments-documents, also available in 

the docket for this rulemaking, Docket Id. No EPA– 

HQ–OAR–2019–0424. 

109One such explanation is that the gas 

processing plant fractionates NGLs to supply fuel 

for use entirely on-site (i.e., the fuel is not supplied 

downstream). Due to definitional differences 

between the two subparts, this facility is defined as 

a fractionator for purposes of subpart W but is not 

a supplier that must report under subpart NN. 

110While it is the EPA’s intention that the 

reported quantity of natural gas received at the 

facility in 40 CFR 98.236(aa)(3)(i) should be the 

quantity of natural gas received for processing, 

consistent with the requirement to report the 

annual volume of natural gas received for 

processing in 40 CFR 98.406(a)(3), some reporters 

have indicated in correspondence with the EPA via 

e-GGRT that they are including gas that is received 

at but not processed by the onshore natural gas 

processing facility (i.e., gas that was processed 

elsewhere and passes through the onshore natural 

gas processing facility). Therefore, to clarify the 

EPA’s intention and reinforce the consistency of the 

subpart W and subpart NN quantities, the EPA is 

proposing to revise 40 CFR 98.236(aa)(3)(i) to 

indicate that that reported quantity should be 

natural gas received at the gas processing plant for 

processing in the calendar year. 

liquid products supplied downstream 

and their associated emissions. For 

example, for natural gas processing 

plants, both subparts require reporting 

of the volume of natural gas received 

and the volume of NGLs received. 

Subpart W also requires reporting of 

total NGLs leaving the processing plant, 

while subpart NN requires reporting of 

the volume of each individual NGL 

product supplied. For LDCs, some 

duplicative reporting is required as 

well. For example, both subparts require 

reporting of the volume of natural gas 

received, volume placed into and out of 

storage each year, and volume 

transferred to other LDCs or to a 

pipeline as well as some other 

duplicative data. In addition, 

commenters stated that the reporting 

elements included in subparts W and 

NN for LDCs are redundant with data 

reported to the U.S. Energy Information 

Administration (EIA) on Form EIA–176, 

the Annual Report of Natural and 

Supplemental Gas Supply and 

Disposition.107 The commenters 

explained that subpart W and subpart 

NN collect nearly the same data, and 

discrepancies between the data sets are 

due to the use of inconsistent 

terminology. Commenters also 

suggested that due to the redundancy 

and availability of data reported to the 

EIA for LDCs, the EPA should remove 

the throughput-related reporting 

requirements for the Natural Gas 

Distribution industry segment from the 

GHGRP altogether. Commenters added 

that if the requirements are maintained, 

the EPA should reconcile the 

terminology used within the GHGRP 

and clarify the reporting elements. 

The EIA report is submitted in the 

spring of each year and covers the 

previous calendar year. After 

completing internal audits of the 

reports, EIA publishes the data for each 

LDC on its website in the fall. The EIA 

data provides detailed information on 

the volume of gas received, gas stored, 

gas removed from storage, gas deliveries 

by sector, and HHV data. The EPA 

previously reviewed the possibility of 

obtaining data by accessing existing 

federal government reporting and 

‘‘decided not to modify the final rule 

because collecting data directly in a 

central system will enable the EPA to 

electronically verify all data reported 

under this rule quickly and consistently, 

to use the information for non-statistical 

purposes, and to handle confidential 

business information in accordance 

with the Clean Air Act.’’ 108 In the 

specific case of subpart NN, in the 2009 

Final Rule, the EPA also ‘‘determined 

that it could not rely on EIA data to 

collect facility-level data from 

fractionators and company-level data 

from LDCs.’’ Additionally, the EPA 

sought ‘‘data that is beyond what EIA 

collects, such as quality assurance 

information, verification data, and 

information on odorized propane’’ and 

‘‘data on site-specific HHV and carbon 

content from those sites that choose to 

sample and test products rather than use 

default emission factors.’’ 

After further review of the data 

available through EIA, the stakeholder 

comments described earlier in this 

section, and the reporting requirements 

in subpart W and subpart NN, the EPA 

is proposing to eliminate duplicative 

elements from subpart W for facilities 

that report to subpart NN, consistent 

with section II.B.3 of this preamble. The 

EPA is proposing to amend the 

reporting requirements in 40 CFR 

98.236(aa)(3) for Onshore Natural Gas 

Processing plants that fractionate NGLs 

(approximately 100 of the 450 subpart 

W natural gas processing plants) and 

also report as a supplier under subpart 

NN. For this subset of facilities, the EPA 

reviewed the data from subpart W and 

subpart NN and determined that there 

are no gas processing plants that report 

as fractionators under subpart W that do 

not also report under subpart NN 

without supplying a valid 

explanation.109 During this review, the 

EPA found that some of the data 

elements included in subpart W overlap 

with data elements in subpart NN. 

Specifically, the data elements in 40 

CFR 98.236(aa)(3)(i), (iii) and (iv) of 

subpart W overlap with data elements in 

subpart NN as specified in 40 CFR 

98.406(a)(3), 98.406(a)(1) and (2), 

98.406(a)(4)(i) and (ii), respectively.110

To eliminate reporting redundancies, 

the EPA is proposing6 several 

amendments to 40 CFR 98.236(aa)(3). 

First, to clarify which facilities have 

data overlap between subparts W and 

NN, the EPA is proposing to add a 

reporting element for natural gas 

processing plants at 40 CFR 

98.236(aa)(3)(viii) to indicate whether 

they report as a supplier under subpart 

NN. Next, the EPA is proposing that 

facilities that indicate that they both 

fractionate NGLs and report as a 

supplier under subpart NN would no 

longer be required to report the 

quantities of natural gas received or 

NGLs received or leaving the gas 

processing plant as specified in 40 CFR 

98.236(aa)(3)(i), (iii) and (iv). These 

facilities would, however, be required to 

continue reporting the data elements 

specified in 40 CFR 98.236(aa)(3)(ii) and 

(v) through (viii), as these reporting 

elements do not overlap with subpart 

NN reporting elements. Natural gas 

processing plants that do not fractionate 

or that fractionate but do not report as 

a supplier under subpart NN would 

continue to report all of the reporting 

elements for natural gas processing 

plants as specified in 40 CFR 

98.236(aa)(3). 

The EPA is also proposing to remove 

the reporting elements for throughput 

for LDCs in 40 CFR 98.236(aa)(9). The 

EPA reviewed the data from subpart W 

and subpart NN and determined that 

there are no LDCs that report under 

subpart W that do not also report under 

subpart NN. In fact, an average of 385 

LDCs report under subpart NN, while 

170 LDCs report under subpart W. 

Subpart NN therefore provides more 

comprehensive coverage of the Natural 

Gas Distribution industry segment. 

Additionally, subpart NN has been in 

effect for LDCs since RY2011 while 

subpart W throughput information has 

only been collected since RY2015; thus, 

subpart NN has a more robust historical 

data set. During this review, the EPA 

determined that the data elements found 

in 40 CFR 98.236(aa)(9)(i) through (v) of 

subpart W overlap with data elements in 

subpart NN as specified in 40 CFR 

98.406(b)(1) through (3), 98.406(b)(5) 

and (6), and 98.406(b)(13). To eliminate 

reporting redundancies, the EPA is 

proposing to remove these reporting 

elements from subpart W. 


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111Letter from Matt Hite, GPA Midstream 

Association, to Mark de Figueiredo, U.S. EPA, Re: 

Additional Information on Suggested Part 98, 

Subpart W Rule Revisions to Reduce Burden. 

September 13, 2019. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

The EPA is also proposing to remove 

the reporting elements for the volume of 

natural gas used for operational 

purposes and natural gas stolen 

specified in 40 CFR 98.236(aa)(9)(vi) 

and (vii). These reporting elements are 

unique to subpart W and have caused 

confusion for subpart W reporters, 

require additional burden to estimate, 

and have not been used for the EPA’s 

analyses of the subpart W data. As a 

result of removing these data elements, 

the EPA proposes to reserve paragraph 

40 CFR 98.236(aa)(9). Table 2 of this 

preamble shows all the duplicative data 

elements that the EPA is proposing to 

remove from subpart W for facilities that 

also report to subpart NN. 

TABLE 2—LIST OF PROPOSED SUBPART W DATA ELEMENTS TO BE REMOVED WHERE ANALOGOUS SUBPART NN DATA

ELEMENTS ARE REPORTED

Subpart W data elements proposed to be eliminated Analogous subpart NN data elements 

Citation Description Citation Description 

Local Distribution Companies.

§ 98.236(aa)(9)(i) ....................... Quantity of natural gas received at all custody transfer 

stations.

§ 98.406(b)(1) ...........................

§ 98.406(b)(5) ...........................

Annual volume of natural gas received by 

the LDC at its city gate stations and Annual volume natural gas that bypassed 

the city gate(s). 

§ 98.236(aa)(9)(ii) ...................... Quantity of natural gas withdrawn from in-system storage.§ 98.406(b)(3) ........................... Annual volume natural gas withdrawn 

from on-system storage and annual volume of vaporized LNG withdrawn from 

storage. 

§ 98.236(aa)(9)(iii) ..................... Quantity of natural gas added 

to in-system storage.

§ 98.406(b)(2) ........................... Annual volume of natural gas placed into 

storage or liquefied and stored. 

§ 98.236(aa)(9)(iv) ..................... Quantity of natural gas delivered to end users.§ 98.406(b)(13)(i) through (iv) ... Annual volume of natural gas delivered by 

the LDC to residential consumers, commercial consumers, industrial consumers, electricity generating facilities. 

§ 98.236(aa)(9)(v) ...................... Quantity of natural gas transferred to third parties.§ 98.406(b)(6) ........................... Annual volume of natural gas delivered to 

downstream gas transmission pipelines 

and other local distribution companies. 

Natural Gas Processing 

Plants that Fractionate 

NGLs.

§ 98.236(aa)(3)(i) ....................... Quantity of natural gas received.§ 98.406(a)(3) ........................... Annual volume of natural gas received for 

processing. 

§ 98.236(aa)(3)(iii) ..................... Cumulative quantity of all NGLs 

(bulk and fractionated) received.

§ 98.406(a)(2) ...........................

§ 98.406(a)(4)(i) ........................

Annual quantity of each NGL product received and annual quantities of y-grade, 

o-grade and other bulk NGLs received. 

§ 98.236(aa)(3)(iv) ..................... Cumulative quantity of all NGLs 

(bulk and fractionated) leaving.

§ 98.406(a)(1) ...........................

§ 98.406(a)(4)(ii) .......................

Annual quantity of each NGL product supplied and annual quantities of y-grade, 

o-grade and other bulk NGLs supplied. 

h. Onshore Natural Gas Processing 

Industry Segment 

According to 40 CFR 98.230(a)(3), the 

Onshore Natural Gas Processing 

industry segment currently includes all 

facilities that fractionate NGLs. The 

industry segment also includes all 

facilities that separate NGLs from 

natural gas or remove sulfur and CO2

from natural gas, provided the annual 

average throughput at the facility is 25 

MMscf per day or greater. The industry 

segment also includes all residue gas 

compression equipment owned or 

operated by natural gas processing 

facilities that is not located within the 

facility boundaries. 

GPA Midstream has expressed 

concern that the current definition of 

the Onshore Natural Gas Processing 

industry segment applies to some 

compressor stations simply because 

they have an amine unit that is used to 

remove sulfur and CO2 from natural gas. 

According to GPA Midstream, it would 

be more appropriate for such facilities to 

be in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segment. GPA Midstream also 

explained that the 25 MMscf per day 

threshold creates additional burden and 

uncertainty for these compressor station 

facilities because they do not know until 

the end of the year whether they will be 

above or below the threshold. Thus, 

they need to collect the applicable data 

for both the Onshore Natural Gas 

Processing industry segment and the 

Onshore Petroleum and Natural Gas 

Gathering and Boosting industry 

segment so that they will have the 

required data for whichever industry 

segment ultimately applies to them. To 

resolve this issue and to promote 

consistency among regulatory programs, 

GPA Midstream recommended 

replacing the onshore natural gas 

processing definition in subpart W with 

the natural gas processing plant 

definition in NSPS OOOOa.111

After review of these comments, we 

are proposing to replace the definition 

of ‘‘Onshore natural gas processing’’ in 

40 CFR 98.230(a) with language similar 

to the definition of ‘‘natural gas 

processing plant’’ in NSPS OOOOa. 

NSPS OOOOa defines ‘‘natural gas 

processing plant (gas plant)’’ as any 

processing site engaged in the extraction 

of NGLs from field gas, fractionation of 

mixed NGLs to natural gas products, or 

both. The definition specifies that a 

Joule-Thompson valve, a dew point 

depression valve, or an isolated or 

standalone Joule-Thompson skid is not 

a natural gas processing plant. There are 

two minor editorial differences between 


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the proposed definition in 40 CFR 

98.230(a) and the definition in NSPS 

OOOOa. First, instead of defining a 

natural gas processing ‘‘plant,’’ as in the 

definition in NSPS OOOOa, we are 

proposing to describe what is meant by 

‘‘natural gas processing’’ so that the 

structure of 40 CFR 98.230(a)(3) is 

consistent with the structure of all of the 

other industry segment definitions in 40 

CFR 98.230(a). Second, the definition in 

NSPS OOOOa refers to ‘‘extraction’’ of 

NGLs from natural gas, but this term is 

not defined. Thus, we are proposing to 

retain the term ‘‘forced extraction’’ in 

the current provisions of 40 CFR 

98.230(a)(3) and revise the definition of 

this term slightly in 40 CFR 98.238. The 

current definition of ‘‘forced extraction’’ 

specifies that forced extraction does not 

include ‘‘portable dewpoint suppression 

skids.’’ We are proposing to revise the 

definition to indicate instead that forced 

extraction does not include ‘‘a JouleThomson valve, a dewpoint depression 

valve, or an isolated or standalone JouleThomson skid.’’ These changes would 

make the definition of ‘‘forced 

extraction’’ in subpart W consistent 

with the language in the definition of a 

natural gas processing plant in NSPS 

OOOOa. This proposed amendment 

would provide reporters with certainty 

about the applicable industry segment 

for the reporting year, reducing the 

monitoring data they must collect to 

only the information needed for the 

applicable industry segment, consistent 

with section II.B.2 of this preamble. 

This proposed amendment is not 

expected to decrease overall coverage of 

the GHGRP for the petroleum and 

natural gas systems industry, although 

we anticipate that some facilities would 

report under a different industry 

segment going forward. Based on 

reported data for RY2020, about 19 

percent of facilities reporting in the 

Onshore Natural Gas Processing 

industry segment do not fractionate 

NGLs and report zero NGLs received 

and leaving the facility. These facilities 

meet the current definition of natural 

gas processing because they are 

separating CO2 and/or hydrogen sulfide. 

These facilities would not meet the 

proposed revised definition for natural 

gas processing and instead, their 

emissions would be reported as part of 

either existing or new onshore 

petroleum and natural gas gathering and 

boosting facilities. In most cases, we 

anticipate that operations at a former gas 

processing facility would be 

incorporated into an existing gathering 

and boosting facility that has been 

subject to reporting, and the total 

emissions from the expanded gathering 

and boosting facility would be similar to 

the emissions that would have been 

reported by the separate facilities under 

the existing industry segment 

definitions. In cases where a former gas 

processing facility is located in a basin 

where the owner or operator does not 

have an existing reporting gathering and 

boosting facility, we expect that a new 

gathering and boosting facility including 

the former gas processing facility would 

be created because the emissions from 

the former gas processing facility alone 

would exceed the reporting threshold of 

25,000 mtCO2e. If the same owner or 

operator has other gathering and 

boosting operations in the same basin 

that have emissions less than 25,000 

mtCO2e, then the new gathering and 

boosting facility could result in 

increased coverage of the industry 

segment and greater total reported 

emissions than would be reported under 

the current industry segment 

definitions. 

The proposed revised definition for 

natural gas processing also does not 

include the 25 MMscf per day threshold 

for facilities that do not fractionate 

NGLs. Under the current definition of 

onshore natural gas processing, 

processing plants that do not fractionate 

gas liquids and generally operate close 

to the 25 MMscf per day threshold do 

not know until the end of the year 

whether they will be above or below the 

threshold, so they must be prepared to 

report under whichever industry 

segment is ultimately applicable. The 

two potentially applicable segments 

report emissions from different sources 

and with different calculation methods. 

For example, facilities in the Onshore 

Natural Gas Processing industry 

segment are not required to report 

emissions from atmospheric storage 

tanks and are required to measure leaks 

from individual compressors, while 

facilities in the Onshore Petroleum and 

Natural Gas Gathering and Boosting 

industry segment are required to report 

emissions from atmospheric storage 

tanks but may use emission factors to 

calculate emissions from compressors 

rather than conducting measurements. 

These sites would meet the revised 

proposed definition of natural gas 

processing regardless of their 

throughput level, so they would have 

the certainty of knowing they would be 

subject to reporting as natural gas 

processing facilities every year, and as 

a result, removing the 25 MMscf per day 

threshold is expected to increase the 

number of facilities that report under 

the Onshore Natural Gas Processing 

industry segment. We request comment 

on the impact the proposed change 

would have on the number of reporting 

facilities and emissions from both the 

Onshore Natural Gas Processing and 

Onshore Petroleum and Natural Gas 

Gathering and Boosting industry 

segments. We also request comment on 

any other advantages or disadvantages 

to finalizing the proposed change. 

Finally, we note that the definition of 

natural gas processing plant in NSPS 

OOOOa does not specifically include 

residue gas compression equipment. 

Residue gas compression is defined in 

40 CFR 98.238 as the compressors 

operated by the processing facility, 

whether inside the processing facility 

boundary fence or outside the fenceline, that deliver the residue gas from 

the processing facility to a transmission 

pipeline. Per 40 CFR 98.230(a)(3), the 

Onshore Natural Gas Processing 

industry segment includes all residue 

gas compression equipment owned or 

operated by the natural gas processing 

plant. We are requesting comment on 

whether to remove the existing 

requirement to include residue gas 

compression equipment owned or 

operated by the natural gas processing 

facility from 40 CFR 98.230(a)(3) and 40 

CFR 98.231(b). If this change were 

finalized, we anticipate that residue gas 

compression equipment would then be 

part of the Onshore Natural Gas 

Transmission Compression industry 

segment, which would require reporters 

with residue gas compression 

equipment that currently only report 

under the Onshore Natural Gas 

Processing industry segment to begin 

reporting under both the Onshore 

Natural Gas Processing and Onshore 

Natural Gas Transmission Compression 

industry segments in order to fully 

report their facility emissions. As part of 

the request for comment on this issue, 

we request comment on the expected 

impact on the level of reported 

emissions that would result if this 

change were finalized. We also request 

comment on other rationale for or 

against finalizing this change. 

3. Other Proposed Minor Revisions or 

Clarifications 

See Table 3 of this preamble for the 

miscellaneous minor technical 

corrections not previously described in 

this preamble that we are proposing 

throughout subpart W, consistent with 

section II.A.5 of this preamble. 


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TABLE 3—PROPOSED TECHNICAL CORRECTIONS TO SUBPART W 

Section (40 CFR) Description of proposed amendment 

98.232(b), 98.233(s), 98.236(s) .......................... Update the outdated acronym ‘‘BOEMRE’’ to the current acronym ‘‘BOEM.’’ 

98.232(b), 98.233(s) ........................................... Update the cross references to the BOEM requirements from ‘‘30 CFR 250.302 through 304’’ 

to ‘‘30 CFR 550.302 through 304.’’ 

98.233(a)(1) ........................................................ Revise the definition of the equation variable ‘‘EFt’’ to consolidate the list of applicable industry 

segments and tables into one sentence. 

98.233(e)(1)(x) .................................................... Add ‘‘at the absorber inlet’’ to the end of the paragraph to clarify the location for the wet natural gas temperature and pressure to be used for modeling. 

98.233(g)(4)(ii) .................................................... Revise the instance of ‘‘formation on N2O’’ in the second sentence to read ‘‘formation of N2O’’ 

to correct a typographical error. 

98.233(j), 98.236(j) ............................................. Revise the instances of ‘‘oil,’’ ‘‘oil/condensate,’’ and ‘‘liquid’’ to read ‘‘hydrocarbon liquids’’ for 

consistency with the requirement in 40 CFR 98.233(j) to calculate emissions from ‘‘atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids,’’ as noted 

in the 2015 amendments to subpart W (80 FR 64272, October 22, 2015). 

98.233(n)(5) ........................................................ Correct the cross reference in the definition of the equation variable ‘‘Yj’’ from paragraph (n)(1) 

to (n)(2). 

98.233(o) introductory text and (p) introductory 

text.

Moved the last sentence in each paragraph to be the second sentence to clarify that the calculation methodology for compressors routed to flares, combustion, and vapor recovery 

apply to all industry segments. 

98.233(p)(1)(i) ..................................................... Correct the internal cross reference from paragraph (o) to paragraph (p). 

98.233(p)(4)(ii)(C) ............................................... Add missing ‘‘in’’ to read ‘‘according to methods set forth in § 98.234(d).’’ 

98.233(r) introductory text .................................. Revise the instance of ‘‘CH’’ in the third sentence to read ‘‘CH4’’ to correct a typographical 

error. 

98.233(r), equations W–32A and W–32B .......... Correct the cross reference in the definition of the equation variable ‘‘Es,MR,i’’ and the equation 

variable ‘‘CountMR’’ from paragraph (q)(9) to (q)(2)(xi). 

98.233(r)(6)(ii) ..................................................... Add reference to components listed in 40 CFR 98.232(i)(3), for consistency with proposed 

amendments to 40 CFR 98.233(r)(6)(i). 

98.233(s) ............................................................. Remove the outdated references to ‘‘GOADS.’’ 

98.233(t)(2) ......................................................... Revise the definition of equation variable ‘‘Za’’ to include the sentence following the definition 

of that variable to correct a typographical error. 

98.233(u)(ii) ......................................................... Format the heading to be in italicized text. 

98.233(z) ............................................................. Revise the instances of ‘‘high heat value’’ to read ‘‘higher heating value’’ to correct inconsistency in the term. 

98.233(z), equations W–39A and W–39B .......... Remove unnecessary ‘‘constituent’’ from ‘‘CO2 constituent’’ and ‘‘methane constituent’’ and remove ‘‘gas’’ from ‘‘gas hydrocarbon constituent.’’ Add missing ‘‘the’’ to read ‘‘to the combustion unit’’ in several variable definitions. 

98.236 introductory text ...................................... Add missing ‘‘than’’ to read ‘‘report gas volumes at standard conditions rather than the gas 

volumes at actual conditions.’’ 

98.236(e)(2) ........................................................ Revise the instances of ‘‘vented to’’ a control device, vapor recovery, or a flare to read ‘‘routed 

to’’ to correct inconsistency in the phrases ‘‘vented to’’ and ‘‘routed to.’’ 

Revise the instances of ‘‘vapor recovery device’’ to read ‘‘vapor recovery system’’ to correct inconsistency in the term. 

98.236(j)(2) ......................................................... Clarify that the reported information in paragraphs (j)(1)(i) through (xvi) should only include 

those atmospheric storage tanks with emissions calculated using Calculation Method 3. 

98.236(l)(1), (2), (3), and (4) introductory text ... Revise the instances of ‘‘vented to a flare’’ to read ‘‘routed to a flare’’ to correct inconsistency 

in the phrases ‘‘vented to’’ and ‘‘routed to.’’ 

98.236(p)(3)(ii) .................................................... Add a missing period at the end of the sentence. 

98.236(bb) ........................................................... Clarify that reporting for missing data procedures includes the procedures used to substitute 

an unavailable value of a parameter (per 40 CFR 98.235(h)). 

98.236(cc) ........................................................... Correct the cross references from paragraph (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), and (l)(4)(iii) to 

(l)(1)(v), (l)(2)(v), (l)(3)(iv), and (l)(4)(iv), respectively. 

98.238 ................................................................. Remove the second definition of ‘‘Facility with respect to natural gas distribution for purposes 

of reporting under this subpart and for the corresponding subpart A requirements’’ to eliminate an inadvertent identical duplicative definition. 

Table W–1A, Table W–3B, and Table W–4B to 

subpart W of part 98.

Change ‘‘Low Continuous Bleed Pneumatic Device Vents’’ to ‘‘Continuous Low Bleed Pneumatic Device Vents’’ and change ‘‘High Continuous Bleed Pneumatic Device Vents’’ to 

‘‘Continuous High Bleed Pneumatic Device Vents’’ to be consistent with the terms used 

throughout the rest of subpart W. 

Table W–3B and Table W–4B to subpart W of 

part 98.

Change table headings and footnotes to clarify that the population emission factors for pneumatic device vents are whole gas emission factors rather than total hydrocarbon emission 

factors. 

4. Best Available Monitoring Methods 

The EPA is proposing that facilities 

would be allowed to use BAMM on a 

short-term transitional basis for the 

proposed amendments for the 2023 

reporting year for only the specific 

industry segments and emission sources 

for which new monitoring or data 

collection requirements are being 

proposed. These industry segments and 

emission sources include calculating 

and reporting emissions from natural 

gas pneumatic devices at onshore 

natural gas processing facilities, natural 

gas intermittent bleed pneumatic 

devices for which the reporter conducts 

routine monitoring surveys, acid gas 

removal vents at LNG import/export 

facilities, other large release events at all 

facilities, miscellaneous flared sources, 

glycol dehydrators and atmospheric 

storage tanks routed to vapor recovery 

systems, compressor sources and modeVerDate Sep<11>2014 20:28 Jun 17, 2022 Jkt 256001 PO 00000 Frm 00077 Fmt 4701 Sfmt 4702 E:\FR\FM\21JNP2.SGM 21JNP2

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source combinations for which new 

measurements would be required, and 

measurements taken using a high 

volume sampler. We are also proposing 

that reporters of an onshore natural gas 

processing facility that becomes part of 

an onshore petroleum and natural gas 

gathering and boosting facility, or vice 

versa, solely due to the proposed change 

in the definition of 40 CFR 98.230(a)(3) 

would be allowed to use BAMM for the 

emission sources for which 

measurements were not required under 

the previous industry segment. This 

proposal would allow reporters to use 

best available methods to estimate 

inputs to emission equations for the 

newly proposed emission sources using 

their best engineering judgment for 

cases where the monitoring of these 

inputs would not be possible beginning 

on January 1, 2023. 

These reporters would have the 

option of using BAMM from January 1, 

2023, to December 31, 2023, without 

seeking prior EPA approval for certain 

parameters that cannot reasonably be 

measured according to the monitoring 

and quality assurance/quality control 

(QA/QC) requirements of 40 CFR 

98.234. This additional time for 

reporters to comply with the monitoring 

methods for new emission sources in 

subpart W would allow facilities to 

install the necessary monitoring 

equipment during other planned (or 

unplanned) process unit downtime, 

thus avoiding process interruptions. The 

EPA is not proposing to allow the use 

of BAMM beyond RY2023 and does not 

anticipate that BAMM would be needed 

beyond 2023 for the specific industry 

segments and emissions sources with 

proposed amendments in this rule. The 

EPA is also not proposing to allow the 

use of BAMM for industry segments and 

emission sources for which no 

amendments have been proposed that 

would require additional data collection 

because reporters should already be 

collecting the measurements and 

activity data needed to meet the 

requirements of the current rule. 

K. Subpart X—Petrochemical 

Production 

We are proposing several 

amendments to subpart X of part 98 

(Petrochemical Production) to improve 

the quality of data reported and to 

clarify the calculation, recordkeeping, 

and reporting requirements for the 

reasons described in this section and in 

section II.A of this preamble. 

For the reasons described in section 

II.A.3 of this preamble, we are 

proposing to add a reporting 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. These sections of 

subpart X currently require reporting of 

the total emissions from each flare that 

burns off-gas from a petrochemical 

process unit for which emissions are 

determined under the CEMS or optional 

ethylene combustion methodologies. We 

are proposing that reporters also report 

estimated fractions of the total CO2, 

CH4, and N2O emissions from these 

flares that are due to combusting 

petrochemical off-gas because the 

current requirements result in an 

overestimate of emissions attributed to a 

petrochemical process unit when the 

flare is not dedicated to a petrochemical 

process unit, particularly if the flare is 

also used to combust off-gas from nonpetrochemical process units. The 

proposed requirement would allow the 

fractions attributed to each 

petrochemical process unit that routes 

emissions to the flare to be estimated 

using engineering judgment. This 

proposed change would allow more 

accurate quantification of emissions 

both from individual petrochemical 

process units and from the industry 

sector as a whole. 

For the reasons described in section 

II.A.4 of this preamble, we are 

proposing to add 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 under the optional 

ethylene combustion methodology. 

Subpart X currently requires reporting 

of only the quantity of ethylene 

produced. The proposed change would 

make product reporting under the 

optional ethylene combustion 

methodology consistent with product 

reporting requirements under the CEMS 

and mass balance reporting options. 

Data on the quantities of all products 

will improve the EPA’s ability to verify 

reported emissions from these process 

units, and the data will be useful in 

informing future policy decisions. 

For the reasons described in section 

II.A.5 of this preamble, we are 

proposing two changes to clarify 

emissions calculation requirements for 

flares. Currently, 40 CFR 98.243(b)(3) 

and (d)(5) cross-reference the 

calculation procedures in 40 CFR 

98.253(b)(1) through (b)(3) of subpart Y. 

We are proposing to revise these 

sections to cross-reference all of 40 CFR 

98.253(b) to clarify that the provisions 

added in past amendments and in this 

amendments package to the 

introductory paragraph in 40 CFR 

98.253(b) also apply to flares that are 

subject to reporting under subpart X. 

This proposed change would clarify that 

subpart X reporters are not required to 

report emissions from combustion of 

pilot gas and, as discussed in section 

III.L of this preamble, that gas released 

during SSM events of <500,000 scf/day 

are excluded from equation Y–3. 

Additionally, we are proposing five 

amendments to clarify subpart X rule 

language pertaining to reporting of 

required data elements. In previous rule 

amendments, we added requirements to 

report the annual quantity of each 

petrochemical product produced from 

each process unit. In making the 

changes, we inadvertently introduced 

some overlapping reporting 

requirements. First, to clarify the 

reporting requirements and eliminate 

confusion for facilities that use the mass 

balance approach, we are proposing to 

amend 40 CFR 98.246(a)(2) to remove 

the requirement to report feedstock and 

product names. The rule currently 

specifies in two places that a reporter 

using the mass balance methodology 

must report the feedstock and product 

names for a subject process unit. The 

requirement in 40 CFR 98.246(a)(2) is to 

report the ‘‘names of products, and 

names of carbon-containing feedstocks.’’ 

The requirement in 40 CFR 

98.246(a)(12) is to report the ‘‘(n)ame 

(. . .) of each carbon-containing 

feedstock included in equations X–1, X– 

2, and X–3 of § 98.243.’’ The 

requirement in 40 CFR 98.246(a)(13) is 

to report the ‘‘(n)ame (. . .) of each 

product included in equations X–1, X– 

2, and X–3.’’ Although the language in 

40 CFR 98.246(a)(2) is slightly different 

from the language in 40 CFR 

98.246(a)(12) and (13), the scope of 40 

CFR 98.246(a)(2) is identical to the 

collective scope of 40 CFR 98.246(a)(12) 

and (13). For example, all gaseous 

carbon-containing feedstocks must be 

entered in the equation X–1 calculation, 

all liquid carbon-containing feedstocks 

must be entered in the equation X–2 

calculation, and all solid carboncontaining feedstocks must be entered 

in the equation X–3 calculation. Thus, 

the current requirement in 40 CFR 

98.246(a)(12) to report the name of each 

carbon-containing feedstock used in any 

of the equations means all carboncontaining feedstocks must be reported, 

which is identical to the requirement in 

40 CFR 98.246(a)(2) to report the names 

of carbon-containing feedstocks. A 

similar analysis applied to the products 

results in the conclusion that the 

current requirement in 40 CFR 

98.246(a)(13) to report the name of each 

product used in any of the equations 

means all products must be reported, 

which is identical to the requirement in 

40 CFR 98.246(a)(2) to report the names 

of products. Note that the rule does not 


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specify reporting of ‘‘carbon-containing’’ 

products; this is unnecessary because 

the term ‘‘product’’ is defined in 40 CFR 

98.248 to mean ‘‘. . .carbon-containing 

outputs. . .’’ To eliminate the 

redundancy, we are proposing to delete 

the requirement to report names of 

products and the names of carboncontaining feedstocks from 40 CFR 

98.246(a)(2) because the same 

requirements are also included in 40 

CFR 98.246(a)(12) for feedstocks and 40 

CFR 98.246(a)(13) for products. 

The second amendment to the mass 

balance reporting requirements is to 

revise 40 CFR 98.246(a)(5) and 40 CFR 

98.246(a)(13) to clarify the 

petrochemical and product reporting 

requirements for integrated ethylene 

dichloride/vinyl chloride monomer 

(EDC/VCM) process units. In a letter 

received from Occidental Chemical 

Company titled ‘‘Request to Consider 

IPCC Balanced EDC/VCM Process 

Studies and Data for the Elimination of 

e-GGRT Validation Messages at VCM 

Production Facilities Reporting Under 

Subpart X,’’ dated July 10, 2015 

(available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424), industry 

representatives indicated that an 

integrated EDC/VCM process unit is a 

continuous process in which the EDC is 

produced as an intermediate that is used 

in the production of VCM; purified EDC 

circulates to the VCM production 

portion of the process, and multiple 

recovery loops recycle unconverted EDC 

from the VCM operations to the EDC 

operations for purification. These 

streams that pass back and forth 

between the EDC and VCM portions of 

the integrated unit are not isolated and 

are not measured in a manner that 

would allow for accurate calculation of 

the amount of intermediate EDC 

produced. Since the amount of EDC 

produced as an intermediate in such 

process units may not be measured, 

subpart X was previously amended to 

allow reporters to consider the entire 

integrated EDC/VCM process unit to be 

the petrochemical process unit 

(proposal at 81 FR 2536, January 15, 

2016; final at 81 FR 89188, December 

16, 2016). At the same time, 40 CFR 

98.246(a)(5) was amended to specify 

that the amount of intermediate EDC 

produced in such units and included in 

the total reported amount of EDC 

petrochemical produced could be based 

on either measurements or an estimate. 

In subsequent years, data reported 

under subpart X of the GHGRP 

indicated that some facilities with an 

integrated EDC/VCM process unit 

withdraw small amounts of the EDC as 

a separate product stream. The 

amendments in 2016 were silent on how 

to report the amount of any EDC that is 

withdrawn as a separate product from 

the integrated unit. The intent of the 

proposed changes is that the amount of 

EDC product not used as an 

intermediate would continue to be 

determined as it would be for a 

standalone EDC process unit, this 

amount of EDC product would be added 

to the amount of intermediate EDC, and 

the total would be reported under 40 

CFR 98.246(a)(5) as the amount of EDC 

petrochemical produced by the 

integrated EDC/VCM process unit. To 

clarify this intent we are proposing to 

revise 40 CFR 98.246(a)(5) to specify 

that 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, 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 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 also 

proposing a harmonizing 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. Reporting as a 

product only the quantity of EDC not 

used in the VCM process is consistent 

with the boundary of the mass balance 

being around the integrated EDC/VCM 

process unit. 

For facilities that use CEMS, we are 

proposing a third amendment 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. In previous 

amendments (81 FR 89188, December 

16, 2016), reporting requirements 

related to the quantity of intermediate 

EDC for an integrated EDC/VCM process 

unit were added to the petrochemical 

quantity reporting requirements at 40 

CFR 98.246(b)(8) for CEMS-monitored 

units that were identical to the reporting 

requirements added to 40 CFR 

98.246(a)(5) that are discussed above for 

mass balance units. This 2016 language 

was added so that the reporting 

requirements would be the same under 

both the mass balance methodology and 

the CEMS methodology. However, an 

EDC manufacturer does not need to 

consider an integrated EDC/VCM 

process unit to be the petrochemical 

process unit when using CEMS since 

vent streams are directly monitored and 

thus recycle streams from the VCM to 

EDC process are not required to be 

quantified as with a mass balance unit. 

Under the mass balance option, the 

amount of product must be a measured 

value because the quantity is used in the 

emissions calculation equation; thus, we 

allowed the entire integrated unit to be 

considered the petrochemical process 

unit so the amount of VCM product 

could be the primary reported product, 

and it would be measured. Under the 

CEMS option, the product quantity is 

used only in data verification 

procedures and other data analyses, and 

the EPA has tentatively determined that, 

for these purposes, reporting an 

estimated value is an acceptable 

alternative to incurring the expense of 

modifying an integrated unit process 

unit so that measurements can be taken. 

Thus, we are proposing to revise 40 CFR 

98.246(b)(8) 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 

proposing a fourth amendment to 40 

CFR 98.246(c)(4) to clarify that the 

names and annual quantities of 

feedstocks that must be reported would 

be limited to feedstocks that contain 

carbon. This proposed change will make 

the feedstock reporting requirement 

under the optional ethylene combustion 

methodology consistent with the 

feedstock reporting requirements under 

the mass balance and CEMS options. 

The fifth proposed change to clarify 

the reporting requirements under 

subpart X consists of clarifying changes 

to 40 CFR 98.246(a)(15). Currently, this 

paragraph specifies that the annual 

average molecular weight must be 

reported for each gaseous feedstock and 

product. The proposed revision would 

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. 

This change would be consistent with 

statements in the definitions of the 

terms for volume or mass in equation X– 

1. We are also proposing to rearrange 

the text in 40 CFR 98.246(a)(15) and 

split the paragraph into two sentences to 

improve clarity. 


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These proposed clarifying changes 

would pose no new monitoring, 

reporting, or recordkeeping 

requirements. We are also proposing 

related confidentiality determinations 

for the new or revised data elements, as 

discussed in section VI of this preamble. 

L. Subpart Y—Petroleum Refineries 

1. Proposed Revisions To Improve the 

Quality of Data Collected for Subpart Y 

We are proposing several 

amendments to subpart Y of part 98 

(Petroleum Refineries) to improve data 

collection, clarify rule requirements, 

and correct an error in the rule. 

For the reasons described in section 

II.A.2 and II.A.4 of this preamble, we are 

proposing to amend some of the 

requirements for DCUs to improve data 

collection and our ability to perform 

verification of reported data for these 

emission sources. During the 

verification of DCU emissions, we noted 

a disproportionate number of facilities 

were messaged with potential emission 

errors that used mass measurements 

from company records to estimate the 

dry coke at the end of the coking cycle 

(as an alternative to estimating this 

quantity using Eq. Y–18a) in 40 CFR 

98.257(b)(41). Through correspondence 

with facilities regarding these potential 

emission errors, we found that the some 

of the errors were due to reporters 

incorrectly determining the mass of 

coke at the end of the coking cycle on 

a wet basis rather than on a dry basis. 

This led to an erroneously high value 

being used for the Mcoke input 

parameters to equation Y–18b, resulting 

in an unusually low value of Mwater and 

subsequently lower-than-expected 

methane emissions. We also found that 

some of the errors were explained by the 

use of a facility-specific bulk density of 

coke that was sufficiently different from 

the default value used in EPA-estimated 

emissions to generate a potential error 

message. Finally, we found that some 

facilities indicated the coke may not be 

completely submerged by water due to 

initiating draining prior to atmospheric 

venting. Such activities undermine 

some of the underlying assumptions of 

the steam generation model being used 

to estimate DCU emissions. In order to 

improve the quality of data collected 

and our ability to ensure the reported 

data are accurate, we are proposing two 

amendments to the DCU provisions. 

The first proposed amendment is 

designed to enhance the reporting and 

recordkeeping specifically for facilities 

using mass measurements from 

company records to estimate Mcoke. 

Currently, facilities using mass 

measurements have less recordkeeping 

requirements than those facilities using 

equation Y–18a to estimate the quantity. 

Facilities using equation Y–18a are 

required to keep records of the drum 

outage, drum height, and the drum 

diameter as specified in 40 CFR 

98.257(b)(42) through (44), while 

facilities using mass measurements from 

company records for Mcoke do not have 

any related reporting or recordkeeping 

other than the recordkeeping 

requirement of the Mcoke quantity in 40 

CFR 98.257(b)(41). Therefore, we have 

limited data available by which to verify 

the reported dry mass of coke at the end 

of the cycle, Mcoke. In order to perform 

more robust and consistent verification 

of all of these reported quantities in 

future years, we are proposing 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 subparagraphs would require 

these 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, ensuring the most 

consistent and accurate data are 

provided. We do not anticipate that the 

proposed data elements would require 

any additional monitoring or data 

collection by reporters, as these data are 

likely already available in existing 

company records. We are proposing 

related confidentiality determinations 

for the additional data elements, as 

discussed in section VI of this preamble. 

The second amendment for DCUs we 

are proposing is to amend equation Y– 

18b in 40 CFR 98.253(i)(2) to include a 

new variable ‘‘fcoke’’ and revise the 

existing descriptions of the ‘‘Mwater’’ 

output and ‘‘Hwater’’ variable. As noted 

in the discussion, some of the facilities 

messaged for potential emission errors 

explained that the coke was not 

completely submerged at the time the 

vessel is vented to the atmosphere, 

which contradicts assumptions 

underlying the calculation 

methodology. First, we are proposing to 

revise the definitions of ‘‘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. The steam 

generation model requires a complete 

accounting of the heat within the unit 

prior to venting or draining since steam 

generation will occur if superheated 

water is drained from the unit prior to 

venting. We are also proposing similar 

revisions to the recordkeeping 

requirements at 40 CFR 98.257(b)(45) 

and (46) to add the phrase ‘‘or draining’’ 

to the description of the records. We are 

also proposing to add a new variable 

‘‘fcoke’’ to equation Y–18b 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 would be 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 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. It is subtracted from the waterfilled coke bed volume to determine the 

volume of water. If the coke bed is not 

completely submerged in the water, 

subtracting the entire volume of coke 

from the water-filled coke bed volume 

will underestimate the actual volume of 

water in the coke drum vessel, resulting 

in an underestimate of the methane 

emissions. Adding the ‘‘fcoke’’ variable to 

the second term in equation Y–18b 

would make the equation universally 

applicable in cases where the coke bed 

is not fully submerged when the coke 

drum is first vented or drained. We are 

also proposing to add a corresponding 

recordkeeping requirement at 40 CFR 

98.257(b)(53). 

We are proposing several clarifying 

changes, for the reasons described in 

section II.A.5 of this preamble. We are 

proposing to add clarifying language to 

40 CFR 98.253(c) and 98.253(e) to 

reiterate the language from 40 CFR 

98.252(b) that the emissions being 

quantified in these paragraphs are coke 

burn-off emissions rather than 

emissions that may occur from other 

venting events. The language at 40 CFR 

98.252(b) clearly indicates that the 

emissions to be reported are ‘‘. . . coke 

burn-off emissions from each catalytic 

cracking unit, fluid coking unit, and 

catalytic reforming unit . . . ’’ 

[emphasis added]. However, the 

language at to 40 CFR 98.253(c) and 

98.253(e) could be construed to apply to 

other vented emissions. We have 

received a GHGRP Help Desk question 

concerning the applicability of the 

calculation methodology to other 

venting events. To help clarify that the 

calculation methodologies in 40 CFR 

98.253(c) and 98.253(e) are specific to 


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coke burn-off emissions, we are 

proposing to add ‘‘from coke burn-off’’ 

immediately after the first occurrence of 

‘‘emissions’’ in the introductory text of 

40 CFR 98.253(c) and 40 CFR 98.253(e). 

We are proposing a clarifying change 

to correct an inconsistency introduced 

into subpart Y by the amendments 

published on December 9, 2016 (81 FR 

89188). The introduction to the flare 

emission calculation requirements at 40 

CFR 98.253(b) was revised in 2016 to 

state that all gas discharged through the 

flare stack must be included in the 

calculations except for pilot gas. The 

intent of this provision was to require 

inclusion of purge and sweep gas in 

addition to SSM events. However, 

because equation Y–3 excludes SSM 

events less than 500,000 scf/day, the 

new provision created an apparent 

inconsistency about whether to include 

or exclude SSM events less than 

500,000 scf/day in equation Y–3. Some 

reporters have interpreted that such 

SSM events must be included. We are 

proposing to clarify 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). This 

proposed clarification corrects the 2016 

amendment, which was not intended to 

eliminate the exclusion when reporters 

use equation Y–3, and would reduce 

repeated verification and correction of 

errors submitted in reports. 

We are proposing a correction to an 

erroneous cross-reference in 40 CFR 

98.253(i)(5) for the reasons described in 

this section and section II.A.5 of this 

preamble. The section inaccurately 

defines the term Mstream in equation Y– 

18f for DCUs. Currently, Mstream is 

defined as, ‘‘Mass of steam generated 

and released per decoking cycle (metric 

tons/cycle) as determined in paragraph 

(i)(3) of this section.’’ The correct crossreference is paragraph (i)(4) instead of 

(i)(3). The proposed change would not 

have any impact on burden. 

Finally, we are proposing a change to 

correct an inconsistency introduced into 

subpart Y by the amendments published 

on December 9, 2016 (81 FR 89188). The 

DCU emission calculations were 

updated in 2016, and, as part of that 

update, 40 CFR 98.253(j) was revised to 

remove the option to calculate CH4

emissions from DCUs using the process 

vent method (equation Y–19). However, 

the DCU recordkeeping requirements for 

the process vent method at 40 CFR 

98.257(b)(53) through (56) were 

inadvertently not removed from the 

rule. We are proposing to revise 40 CFR 

98.257(b)(53) to include recordkeeping 

requirement for the ‘‘fcoke’’ variable, as 

previously discussed in this section, 

and to remove and reserve the 

recordkeeping requirements in 

paragraphs 98.257(b)(54) through (56) 

since equation Y–19, the process vent 

calculation method, is no longer used to 

calculate DCU emissions. 

2. Proposed Revisions To Streamline 

and Improve Implementation for 

Subpart Y 

For the reasons described in this 

section and in section II.B.2 of this 

preamble, we are proposing to allow the 

use of mass spectrometer analyzers to 

determine gas composition and 

molecular weight without the use of a 

gas chromatograph. Currently, the 

methods for determining gas 

composition in 40 CFR 98.254(d) rely on 

gas chromatography. Advances in data 

analytics have made it easier for mass 

spectrometer analyzers to determine 

concentrations of individual 

compounds from a mixture of 

hydrocarbons without the need for preseparation of the compounds using gas 

chromatography. Direct analysis using 

mass spectrometer analyzers greatly 

reduces the cycle time between sample 

analyses, allowing improved process 

control. As such, some refinery owner/ 

operators use direct mass spectrometer 

analyzers to determine gas stream 

composition. The proposed inclusion of 

direct mass spectrometer analysis as an 

allowable gas composition method in 40 

CFR 98.254(d) would allow these 

reporters to use the same analyzers used 

for process control or for compliance 

with continuous sampling required 

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. Currently, 

these reporters have to conduct separate 

periodic sampling of these gas streams 

for analysis using gas chromatography 

to comply with GHGRP requirements in 

subpart Y. Thus, the proposed inclusion 

of mass spectrometer analyzers for 

determining gas composition will 

reduce the burden for these reporters. It 

is also expected to provide more 

accurate data due to the use of 

continuous analyzers rather than 

periodic sampling. 

M. Subpart BB—Silicon Carbide 

Production 

For the reasons described in section 

II.A.4 of this preamble, we are 

proposing revisions to the reporting 

requirements for subpart BB of part 98 

(Silicon Carbide Production) to improve 

the quality of the data collected under 

the GHGRP. 

The original 2009 GHG Reporting 

Rule for silicon carbide production 

required reporting CH4 emissions by 

measuring petroleum coke consumption 

and applying a default CH4 emission 

factor of 10.2 kilograms of CH4 per 

metric ton of coke consumed (see 74 FR 

56260). However, in 2013, we removed 

the requirement for silicon carbide 

production facilities to report CH4

emissions from silicon carbide process 

units or furnaces and the CH4

calculation methodology because we 

determined that the then-current CH4

calculation methodologies in subpart BB 

overestimated the emissions of CH4

from silicon carbide facilities. At the 

time we determined the following: the 

equations did not take into 

consideration the destruction of CH4

emissions, the CH4 emissions from these 

facilities were typically controlled, the 

CH4 emissions from these facilities were 

minimal, and the requirement to report 

CH4 emissions was not necessary to 

understand the emissions profile of the 

industry (see 78 FR 19802, April 2, 

2013, and 78 FR 71904, November 29, 

2013). The determination to not require 

reporting of CH4 emissions was 

predicated on the conclusion that 

because CH4 emissions are typically 

controlled, CH4 emissions from these 

facilities are minimal. Although our 

understanding is still that CH4

emissions are typically controlled, we 

are proposing to amend the rule in order 

to gather more information on CH4

control practices at silicon carbide 

production facilities to better 

understand the extent of those control 

practices and their impact on CH4

emissions. Specifically, we are 

interested in how the CH4 emissions are 

controlled, the efficiency of the control 

technologies, and to what extent these 

technologies are operated throughout 

the year. As such, we are proposing 

adding new reporting requirement 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; (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. The 

proposed reporting requirements would 

be used to confirm the operation and 

efficiency of CH4 abatement at silicon 

carbide facilities and would enable us to 

determine whether the EPA’s 2013 

determination that CH4 emissions are 

typically controlled (and therefore 

minimal) remains accurate. Although 


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silicon carbide facilities would continue 

to not be required to estimate CH4

emissions from their processes for their 

GHGRP annual report, providing data 

on CH4 abatement technology and usage 

would allow the EPA to assess the 

potential for unabated CH4 emissions 

that may influence the industry’s 

emission profile under the GHGRP. We 

also anticipate that we could use this 

kind of information to better understand 

methane emission control practices at 

silicon carbide facilities, to improve the 

EPA’s knowledge of CH4 emissions that 

may be useful for other CAA programs, 

or to support future climate change 

policies, non-regulatory initiatives, or 

regulations under the CAA. The 

proposed data could also be used to 

help estimate CH4 emissions from 

silicon carbide facilities at the national 

level, and thereby inform and improve 

the U.S. GHG Inventory by allowing for 

more accurate estimates that account for 

CH4 removal. 

We are also proposing that 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 

provide the name of the test method that 

was used during the performance test. 

We note that the collection of data 

elements related to GHG abatement and 

methane destruction are consistent with 

other subparts such as subparts E 

(Adipic Acid Production), I (Electronics 

Manufacturing), V (Nitric Acid 

Production), HH (Municipal Solid 

Waste Landfills), and FF (Underground 

Coal Mines) of part 98. For these 

subparts, reporters are typically 

provided an option to account for the 

destruction of methane in their 

estimated emissions (e.g., fluorinated 

gases abated in electronics 

manufacturing processes or collection 

and destruction of methane at MSW 

facilities) and provide similar 

information on the type of abatement 

technology, hours of operation, and 

destruction or control efficiencies. This 

data is typically used for verification of 

emissions estimates and to confirm 

where process technologies or control 

measures result in minimal emissions. 

The collection of abatement data from 

silicon carbide facilities would be 

consistent with this practice. Finally, 

we are proposing that upon reporting 

this information once in an annual 

report, reporters would not be required 

to report this information again unless 

the information changed during another 

reporting year, in which case, the 

reporter would update the information 

in the submitted annual report. 

However, if it appeared that operational 

practices change at facilities such that 

CH4 emissions are not consistently 

controlled from year to year or that 

unabated CH4 emissions may be a more 

substantive contributor to industry 

emissions, then the EPA may consider 

whether it would be beneficial to 

reintroduce CH4 calculation 

methodology and reporting 

requirements. We are proposing adding 

recordkeeping requirement 40 CFR 

98.287(d) for facilities to maintain a 

copy of the reported data. 

Based on review of available permits, 

we anticipate that reporters could obtain 

the proposed data elements from data 

that is collected and readily available to 

facilities as part of their standard 

operation. For example, as part of 

normal operations, we assume facilities 

would keep records of any time that the 

CH4 abatement technology was not in 

use; therefore, the facility could then 

calculate the percent of total operating 

hours that the abatement technology 

was not in use. We are soliciting 

comment on whether this assumption is 

correct. We are also proposing related 

confidentiality determinations for the 

additional data elements, as discussed 

in section VI of this preamble. 

We are also seeking comment on 

alternative methods for determining 

destruction efficiency (i.e., methods 

other than using either the 

manufacturer’s specified destruction 

efficiency or the destruction efficiency 

determined via a performance test). For 

example, we are considering whether it 

would be more reasonable to allow for 

the ‘‘lesser of manufacturer’s specified 

destruction efficiency and 0.99,’’ as is 

required in subpart HH. 

N. Subpart DD—Electrical Transmission 

and Distribution Equipment Use 

1. Proposed Revisions To Improve the 

Quality of Data Collected for Subpart 

DD 

For the reasons discussed in section 

II.A.3 of this preamble, we are 

proposing several revisions to subpart 

DD of part 98 (Electrical Transmission 

and Distribution Equipment Use) to 

improve the quality of the data collected 

from this subpart. These include adding 

F–GHGs other than SF6 and PFCs to the 

monitoring, calculation, and reporting 

requirements of subpart DD (at 40 CFR 

98.302, 98.303, 98.304, 98.305, and 

98.306), clarifying the definition in 40 

CFR 98.308 for ‘‘facility,’’ adding 

definitions for ‘‘energized,’’ ‘‘insulating 

gas,’’ ‘‘new equipment,’’ and ‘‘retired 

equipment,’’ and specifying procedures 

in 40 CFR 98.303(b) for establishing 

user-measured nameplate capacity 

values for new and retiring equipment. 

Currently, this subpart includes all 

electric transmission and distribution 

equipment and servicing inventory 

insulated with or containing SF6 or 

PFCs used within an electric power 

system. We are proposing to revise the 

existing calculation, monitoring, and 

reporting requirements of subpart DD to 

require reporting of additional F–GHGs 

as defined under 40 CFR 98.6. At the 

time of the 2010 Final Rule for 

Additional Fluorinated GHGs, SF6 was 

the most commonly used insulating gas 

in the electrical power industry, and 

PFCs were occasionally used as 

dielectrics and heat transfer fluids in 

power transformers. During the 

implementation of the reporting 

program, electrical power systems 

equipment manufacturers and F–GHG 

suppliers have introduced alternative 

technologies and replacements for SF6

with lower GWPs, including fluorinated 

gas mixtures, such as fluoronitriles or 

fluoroketones mixed with carrier gases 

(e.g., CO2 and O2), as a replacement for 

dielectric insulation gases. The GWPs of 

these gases are generally much lower 

than the GWP of SF6; the GWPs of 

fluoronitrile mixtures are typically 

estimated to fall between 300 and 500, 

whereas the GWPs of fluoroketone 

mixtures are usually estimated to be less 

than 1. The EPA is aware that some 

electric power systems are currently 

using or considering use of these 

alternative gas mixtures; Therefore, we 

are proposing revisions to the reporting 

requirements in order to capture 

emissions from equipment using these 

alternative gases that are not currently 

accounted for. While the use of 

alternative insulation gases will 

generally result in lower GHG 

emissions, we would expect that that 

increased usage of these alternative 

technologies, particularly fluoronitrile 

mixtures, could still significantly 

contribute to the total GHG emissions 

from this sector if used in large 

quantities. The proposed reporting of 

these additional F–GHGs would 

improve the accuracy and completeness 

of the emissions reported under subpart 

DD and enhance the overall quality of 

the data collected under the GHGRP. 

To implement these revisions, we are 

proposing at 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).’’ As discussed 

in section III.N.2 of this preamble, the 

proposed changes would also apply to 

the threshold in 40 CFR 98.301. Under 


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112U.S. EPA. ‘‘Q852. What equipment should be 

included as new or retired equipment each year for 

Subpart DD?’’ April 6, 2020. https://

ccdsupport.com/confluence/pages/ 

viewpage.action?pageId=721715270. 

the proposed rule, both electric power 

systems and electric generating units 

with insulated equipment would also 

consider any additional F–GHGs, 

including those in F–GHG mixtures, 

used at the facility in the nameplate 

capacity used for estimating the 

threshold. At this time, we are unaware 

of any facilities that currently use the 

alternative gas mixtures exclusively or 

in large quantities that would render 

them newly subject to the subpart; 

therefore, we expect the minimal 

burden from the proposed requirements 

would fall on existing reporters, who 

would only be required to account for 

the additional F–GHGs in their gasinsulated equipment (GIE) and 

inventory. 

The proposed revisions to subpart DD 

include minor revisions to equation 

DD–1 (which would be redesignated as 

equation DD–3 at 40 CFR 98.303(a) 

under this proposed rule) to incorporate 

the estimate of emissions from all F– 

GHGs within the existing calculation 

methodology, including F–GHG 

mixtures. Equation DD–3 would 

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 

would require applying the weight 

fraction of each F–GHG to determine the 

user emissions by gas. It is our 

understanding that facilities receive gas 

in equipment pre-mixed and do not mix 

the gas themselves; therefore, the 

proposed revisions assume that facilities 

will track the mixtures received, and 

rely on supplier data to obtain the 

weight fraction of each F–GHG within 

equipment containing a gas mixture. 

Facilities would need to track mixtures 

with unique weight fractions of 

individual F–GHGs separately. 

However, we are seeking comment on 

whether the weight fraction of 

individual F–GHGs is readily available 

from supplier data. We are also seeking 

comment on whether there are facilities 

that mix gas in equipment on site, or 

that expect to mix gas in equipment at 

the facility in the future, and whether 

we should account for this mixing in the 

current equation. Since we assumed that 

gases are typically received pre-mixed, 

the proposed changes include reporting 

of an ID number or descriptor for each 

insulating gas and the name and weight 

percent of each fluorinated gas of each 

insulating gas reported. To simplify 

references to F–GHGs and F–GHG 

mixtures throughout the subpart 

(especially in equation DD–3), we are 

proposing to introduce the term 

‘‘insulating gas’’ and to define it as 

follows: ‘‘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.’’ The proposed 

changes also include updating the 

monitoring and quality assurance 

requirements at 40 CFR 98.304(b) to 

account for emissions from additional 

F–GHGs, and harmonizing revisions to 

the term ‘‘facility’’ in the definitions 

section at 40 CFR 98.308, and the 

requirements at 40 CFR 98.302, 40 CFR 

98.305, and 40 CFR 98.306 such that 

reporters would account for the mass of 

each F–GHG for each electric power 

system. The proposed changes would 

not significantly revise the existing 

calculation, monitoring, or reporting 

requirements; therefore, we expect only 

a minimal increase in burden due to the 

collection of data for any equipment 

containing F–GHGs that are not SF6 or 

PFCs. We are proposing related 

confidentiality determinations for the 

revised data elements that incorporate 

additional F–GHGs, as discussed in 

section VI of this preamble. We are 

proposing one additional change to 

remove an outdated monitoring 

provision at 40 CFR 98.304(a), which 

reserves a prior requirement for use of 

BAMM that applied solely for RY2011. 

For the reasons described in section 

II.A.5 of this preamble, we are also 

proposing to add new definitions to 

clarify the existing provisions of the 

rule. The mass balance methodology in 

40 CFR 98.303 (used for calculating 

facility emissions) uses the terms ‘‘new’’ 

and ‘‘retired’’ to describe equipment 

added to or removed from active use, 

and reporters are required to report 

nameplate capacity and the number of 

F–GHG containing pieces of any new 

and retired equipment. We have 

previously received questions from 

reporters regarding what equipment 

should be included as new or retired 

equipment each year, and we developed 

interpretations of these terms for our list 

of Frequently Asked Questions.112 We 

are proposing to adopt the previous 

interpretations into the rule’s 

requirements in order to help ensure 

that reporters correctly estimate 

emissions, which would improve the 

quality of the data collected. The 

proposed revisions would also reduce 

time spent searching the list of 

Frequently Asked Questions or 

responding to questions through the 

GHGRP Help Desk. 

First, we are proposing a definition at 

40 CFR 98.308 of ‘‘energized’’ to more 

clearly designate what equipment is 

considered to be installed and 

functioning as opposed to being in 

storage. The proposed definition 

clarifies that energized equipment 

includes gas-insulated equipment 

(including hermetically-sealed pressure 

switchgear) that is connected through 

busbars or cables to an electrical power 

system or that is fully-charged, ready for 

service, and being prepared for 

connection to the electrical power 

system, and does not include spare GIE 

(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. Consistent 

with our previous interpretation, we are 

proposing to add a definition for ‘‘new 

equipment’’ to mean any GIE, 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. Similarly, 

we are proposing a definition for 

‘‘retired equipment’’ to mean any GIE, 

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. Finally, we are clarifying that (1) 

new equipment may also include 

equipment 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), and (2) 

retired equipment may also include 

equipment 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 of 

‘‘energized,’’ ‘‘new equipment,’’ and 

‘‘retired equipment’’ are intended to 

clarify how these terms should be 

interpreted for purposes of the equation 

used to estimate emissions for annual 

reporting (i.e., the current equation DD– 

1, which we are proposing to 

redesignate as equation DD–3). This 

equation uses a mass-balance approach 

that assesses annual net gas 

consumption (based on the decrease in 

gas inventory and gas acquisitions and 

disbursements) and accounts for gas 

used or freed up, respectively, by 

equipment installations and 


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113This particularly applies to closed-pressure 

equipment. Closed-pressure equipment is typically 

delivered to the facility without a full and proper 

charge of insulating gas and therefore must be filled 

to the full and proper charge before it is energized. 

Similarly, closed-pressure equipment is typically 

emptied of insulating gas before it is sent off-site for 

recycling or disposal. Hermetically sealed-pressure 

equipment, on the other hand, is generally expected 

to be fully charged upon delivery unless it has 

leaked en route. Hermetically sealed-pressure 

equipment is also often sent off-site (e.g., returned 

to the equipment manufacturer) with its charge 

intact unless it has leaked over its lifetime. 

114Note that this logic does not necessarily apply 

to equipment that is ‘‘new’’ or ‘‘retired’’ because it 

is transferred to or from another owner while it 

remains energized. In this case, we are assuming 

that insulating gas is not generally added to or 

removed from equipment upon transfer, and that 

both the transferring and receiving facilities would 

presume that the equipment is transferring with its 

full and proper charge, meaning that the transfer of 

such equipment would not affect the emissions 

calculated under the mass-balance equation. We 

request comment on whether this assumption is 

correct. 

115State of California Air Resources Board, 

‘‘Regulation for Reducing Sulfur Hexafluoride 

Emissions from Gas Insulated Switchgear.’’ 

Available at https://ww2.arb.ca.gov/rulemaking/ 

2020/sf6?utm_medium=email&utm_

source=govdelivery. 

116Electrical equipment manufacturers indicate 

that this is because the rated nameplate capacity 

was historically only intended to indicate the 

approximate mass of gas required to fill equipment. 

The full and proper charge for a given model of 

equipment can vary from year to year and even 

from one piece of equipment to the next due to 

minor design changes and manufacturing 

variability. To ensure that the equipment functions 

correctly, manufacturers provide precise 

instructions for filling to the proper density. (The 

Electric Transmission & Distribution SF6 Coalition 

(administered by NEMA), SF6 Reporting Challenges, 

undated. Accessed at https://www.nema.org/docs/ 

default-source/products-document-library/sf6- 

reportingchallenges.pdf on June 3, 2021.) 

117See documents ‘‘HELPDESK–64899’’ and 

‘‘HELPDESK–30364’’, available in the docket for 

this rulemaking (Docket Id. No. EPA–HQ–OAR– 

2019–0424). 

retirements.113 The nameplate capacity 

of new equipment is subtracted from the 

total, reflecting the fact that some of the 

insulating gas consumed is used to fill 

the new equipment, while the 

nameplate capacity of retiring 

equipment is added to the total, 

reflecting the fact that the gas formerly 

used to fill the retiring equipment, 

unless emitted, would either be added 

to the gas inventory or disbursed (e.g., 

to an SF6 recycling company). Implicit 

in this approach are the assumptions 

that ‘‘new’’ equipment is filled with 

insulating gas during the same year that 

it is considered ‘‘new,’’ and that 

‘‘retired’’ equipment is emptied of 

insulating gas during the same year that 

it is considered ‘‘retired.’’ 114 We request 

comment on whether new equipment is 

typically filled with gas during the same 

year that it is ‘‘energized’’ under the 

proposed definition of ‘‘energize,’’ and 

on whether retiring equipment is 

typically emptied of gas during the same 

year that it ceases to be ‘‘energized’’ 

under the proposed definition. If gas is 

added to or removed from ‘‘new’’ and/ 

or ‘‘retired’’ equipment in a year 

different from the year that the 

equipment is energized or ceases to be 

energized, respectively, it may be 

clearer to directly tie the terms ‘‘new’’ 

and ‘‘retired’’ to the filling and 

emptying of the equipment (for closedpressure equipment). 

In 40 CFR 98.303(b) we are proposing 

to require 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. This option 

would be available only for closedpressure equipment with a voltage 

capacity greater than 38 kV, not for 

hermetically sealed pressure equipment 

or smaller closed-pressure equipment. 

The 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 also intended to be 

similar to and compatible with the 

procedures for measuring nameplate 

capacity adopted by the California Air 

Resources Board (CARB) in its 

Regulation for Reducing Sulfur 

Hexafluoride Emissions from Gas 

Insulated Switchgear (effective January 

1, 2022).115

As discussed above, the nameplate 

capacities of new and retiring electrical 

equipment are used in the current 

equation DD–1 of subpart DD (which 

would be redesignated as equation DD– 

3 under this proposed rule), which 

calculates annual GHG emissions from 

the equipment. In the equation, 

nameplate capacity is defined as 

referring to ‘‘the full and proper charge 

of equipment rather than to the actual 

charge, which may reflect leakage.’’ 

With each piece of electrical equipment, 

electrical equipment manufacturers 

typically provide a rated nameplate 

capacity in pounds of SF6 (or other 

insulating gas) on a nameplate affixed to 

the equipment and/or in the product 

specifications. When the EPA 

promulgated subpart DD, we expected 

that users of electrical equipment would 

be able to use these rated nameplate 

capacities in their emissions 

calculations without introducing any 

errors. Experience has shown, however, 

that even when users of electrical 

equipment follow industry-accepted 

equipment filling and gas measuring 

methods, the mass of insulating gas 

contained in the equipment when it is 

filled to the manufacturer-specified 

density can sometimes differ from that 

specified on the nameplate. That is, the 

actual nameplate capacity of the 

equipment (the full and proper charge) 

can differ from the rated nameplate 

capacity of the equipment.116

Differences between the actual and 

rated nameplate capacities may result in 

either under- or over-estimates of 

emissions in the short run, depending 

on: (1) whether the actual nameplate 

capacity is greater than the rated 

nameplate capacity or vice versa; and 

(2) whether the equipment is being 

commissioned or retired. For example, 

if the actual nameplate capacity of new 

equipment is larger than the rated 

nameplate capacity of that equipment, 

emissions will be overestimated, 

because some of the gas that was 

actually used to fill the new equipment 

will be assumed to have been emitted. 

On the other hand, if the actual 

nameplate capacity of retiring 

equipment is larger than the rated 

nameplate capacity of the equipment, 

emissions will be underestimated (and 

may even be calculated as negative), 

because the quantity of gas recovered or 

emitted from the retiring equipment will 

be larger than is accounted for by the 

equation. (More scenarios are described 

in the document Technical Support for 

Proposed Revisions to Subpart DD 

(2021) included in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424.) 

As the above example shows, these 

underestimates and overestimates from 

a piece of equipment would cancel out 

over the lifetime of the equipment. To 

some extent, they may also cancel out 

in any given year because rated 

nameplate capacities can be either larger 

or smaller than the actual nameplate 

capacities, and most electrical 

equipment users are likely to both 

install and retire several pieces of 

equipment during the year. However, if 

a large piece of electrical equipment (or 

several smaller pieces of electrical 

equipment) is installed or retired in a 

given year, an error in the rated 

nameplate capacity of that equipment 

could potentially have a significant 

impact on the calculated emissions from 

the electrical equipment user in that 

year. 

For this reason, when electrical 

equipment users have asked the EPA via 

the Helpdesk whether they may use a 

nameplate capacity value different from 

the rated nameplate capacity value in 

their calculations and reporting under 

subpart DD, we have responded 117 that 


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118State of California Air Resources Board, 

‘‘Notice of Public Availability of Modified Text: 

Proposed Amendments to the Regulation for 

Reducing Sulfur Hexafluoride Emissions from Gas 

Insulated Switchgear,’’ May 5, 2021, pp. 17–18. 

they may use the nameplate capacity 

value that corresponds to the full and 

proper charge of the equipment, which 

is determined based on density (e.g., the 

temperature-corrected pressure of the 

equipment) per the manufacturer’s 

filling instructions. We have also noted 

that subpart DD does not currently 

specify a method for calculating 

nameplate capacity values, but for the 

mass-balance approach to yield correct 

results, the nameplate capacity value 

should reflect any shipping charge 

contained in the equipment upon 

delivery, and the same nameplate 

capacity value should be used 

throughout the life of the equipment. 

Finally, we have noted that paragraph 

98.3(g)(2) requires equipment users to 

keep records of the method used to 

calculate the nameplate capacity value. 

The process that we are proposing in 

this action would elaborate on and 

adopt this guidance into the rule’s 

requirements. It is designed to avoid a 

number of potential errors by equipment 

users that can result in inaccuracies in 

the nameplate capacities that they 

measure. Such errors can occur when: 

• Equipment is deliberately overfilled 

or underfilled; 

• Shipping charges are accounted for 

incorrectly or not at all; 

• Inaccurate weigh scales, 

flowmeters, pressure gauges, or 

thermometers are used to fill 

equipment; 

• The temperature of the insulating 

gas is not measured accurately when the 

equipment is filled or emptied (e.g., the 

temperature of the gas is incorrectly 

equated to the ambient temperature); 

• The insulating gas in equipment 

(especially retiring equipment) is not 

completely recovered (or the gas 

remaining in the equipment is not 

accounted for); 

• Previous leakage from equipment 

(especially retiring equipment) is not 

accounted for; or 

• Insulating gas in hoses and gas carts 

is not accounted for. 

To avoid these potential errors, the 

EPA is proposing certain requirements 

at 40 CFR 98.303(b) for when electrical 

equipment users measure the nameplate 

capacity of new equipment that they 

install. These proposed requirements for 

new equipment would help ensure that 

electrical equipment users: 

• Correctly account for the mass of 

insulating gas contained in equipment 

upon delivery from the manufacturer 

(i.e., the holding charge); 

• Use flowmeters or weigh scales that 

meet certain accuracy and precision 

requirements to measure the mass of 

insulating gas added to 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, allowing appropriate time 

for temperature equilibration; and 

• Ensure that insulating gas 

remaining in hoses and gas carts is 

correctly accounted for. 

The EPA is also proposing certain 

requirements at 40 CFR 98.303(b) for 

when electrical equipment users 

measure the nameplate capacity of 

retiring equipment. These proposed 

requirements for retiring would help 

ensure that electrical equipment users: 

• Correctly account for the mass of 

insulating gas contained in equipment 

upon retirement, measuring the actual 

temperature-adjusted pressure and 

comparing that to the temperatureadjusted 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 recovered from the 

equipment; 

• Use pressure-temperature charts 

and pressure gauges and thermometers 

that meet certain accuracy and precision 

requirements 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. 

We are proposing at 40 CFR 

98.303(b)(6) that instead of measuring 

the nameplate capacity of electrical 

equipment when it is retired, users may 

measure the nameplate capacity of 

electrical equipment earlier during 

maintenance activities that require 

opening the gas compartment. In this 

case, the equipment user would 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 would 

be recorded but would not be used in 

equation DD–3 until that equipment was 

actually retired. 

As previously mentioned, only 

closed-pressure equipment with a 

voltage capacity greater than 38 kV 

would be eligible for nameplate capacity 

measurement and correction. This is 

because the quantities of insulating gas 

that are typically inside hermetically 

sealed-pressure equipment and in 

closed pressure equipment with smaller 

voltage capacities are individually and 

collectively less significant than those 

in closed-pressure equipment with 

voltage capacities at or above 38 kV. 

Consequently, any errors in the rated 

nameplate capacities of smaller 

equipment are not likely to have a 

significant impact on the calculated 

emissions of equipment users, and 

efforts to correct the nameplate capacity 

values of smaller equipment do not 

appear to be justified by the 

improvement in accuracy that would 

result. CARB has established eligibility 

criteria similar to those we are 

proposing based on their finding that 

the criteria would cover ‘‘approximately 

23 percent of California’s GIE [gas 

insulated equipment] and 

approximately 80 percent of the SF6

used in the State.’’ 118 In addition, users 

rarely add or remove gas to or from 

hermetically sealed-pressure equipment, 

by design. We request comment on the 

proposed eligibility criteria. 

We are proposing a scheme in 40 CFR 

98.303(b) that would require all eligible 

new and retiring equipment to be 

treated consistently with respect to the 

measurement and adoption of 

nameplate capacities. To avoid biases 

that could result from measuring and 

adopting nameplate capacities for some 

pieces of eligible new or retiring 

equipment but not others, electrical 

equipment users electing to measure the 

nameplate capacities of any new or 

retiring equipment would 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 would 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 differed from the rated 

nameplate capacity by two percent or 

more, the electrical equipment user 

would 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 differed from the rated 

nameplate capacity by less than two 

percent, the electrical equipment user 

would 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 would be required to adopt 

the user-measured nameplate capacities 

for all new and retiring equipment 


jspears on DSK121TN23PROD with PROPOSALS2
37004 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

119Attachment A: Modifications to the Proposed 

Regulation Order, California Air Resources Board, 

available at https://ww3.arb.ca.gov/board/15day/ 

sf6/15dayatta.pdf. 

120 3.5 Torr is a common ‘‘blank-off pressure’’ to 

which gas carts are designed to recover insulating 

gas from electrical equipment. At 3.5 Torr, the EPA 

estimates that 0.1 percent of the full and proper 

charge of insulating gas would remain in the 

equipment, assuming that a full and proper charge 

has a pressure of 5 atmospheres (3800 Torr). We are 

therefore proposing to treat quantities of gas 

remaining at pressures of 3.5 Torr and below as 

negligible in nameplate capacity calculations. 

121Equipment users could also use a hybrid 

approach wherein they would top up the 

equipment but account mathematically for any gas 

remaining in equipment at a pressure above 0.068 

psia. 

whose user-measured nameplate 

capacity differed from the rated 

nameplate capacity by less than two 

percent. As is the case for the proposed 

requirement to consistently measure or 

not measure the nameplate capacities of 

all new and retiring equipment, the 

proposed requirement to consistently 

adopt or not adopt the user-measured 

nameplate capacities where they differ 

from the rated nameplate capacity by 

less than two percent is intended to 

avoid bias that could result from 

adopting only a subset of the usermeasured nameplate capacities that fall 

into this category. 

We are proposing the two-percent 

tolerance for differences between the 

user-measured and rated nameplate 

capacities because, given the precisions 

and accuracies that we are proposing for 

the measuring devices (scales, gauges, 

etc.) used to calculate nameplate 

capacities (as discussed further in this 

section), differences of one percent or 

less are not expected to be 

mathematically meaningful. We request 

comment on the value of two percent 

and on whether the percentage tolerance 

should be supplemented by an absolute 

tolerance, such as 100 pounds of SF6

(equivalent to 1,034 mtCO2e). In the 

latter case, differences equal to or 

greater than the lesser of two percent or 

100 pounds would trigger the 

requirement to use the user-measured 

nameplate capacity. The drawback of 

using a separate absolute tolerance is 

that this tolerance may not be 

mathematically meaningful if the full 

and proper charge of the equipment 

exceeded 10,000 pounds. 

Our proposal to allow electrical 

equipment users to adopt the usermeasured nameplate capacity even 

when the difference between that 

capacity and the rated capacity is less 

than two percent is based on our desire 

to maintain as much consistency as 

possible between GHGRP requirements 

and the proposed requirements of 

CARB. Our understanding is that CARB 

is proposing 119 to require electrical 

equipment users in California to 

measure the nameplate capacity of all 

newly installed closed pressure 

equipment with a voltage capacity 

greater than 38 kV and to adopt the 

measured value irrespective of the 

magnitude of the difference between the 

measured value and the manufacturersupplied value. 

When electrical equipment is retired, 

the quantity of the gas remaining in the 

equipment may reflect leakage that has 

occurred since the last time the 

equipment was serviced or re-filled. In 

this case, we are proposing at 40 CFR 

98.303(b)(5) to allow equipment users to 

account for the leakage using one of two 

approaches. In both approaches, 

equipment users would: (1) measure the 

temperature-compensated pressure of 

the equipment before they removed the 

insulating gas from that equipment; and 

(2) compare the measured temperaturecompensated 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 was 

different from the temperaturecompensated pressure corresponding to 

the full and proper charge of the 

equipment, the equipment user could 

either (a) add or remove insulating gas 

to or from the equipment until the 

equipment reached 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,120 and weigh the 

recovered gas (charge adjustment 

approach), or (b) if the measured 

temperature-compensated pressure was 

at least 90 percent of the temperaturecompensated design operating pressure, 

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). In the mathematical 

adjustment approach, proposed as 

equation DD–4, the equipment user 

would calculate the mass of the full and 

proper charge by scaling up the mass 

recovered by the ratio of pressures (in 

absolute terms) corresponding to the full 

and proper charge and the actual charge, 

respectively, accounting for any 

insulating gas remaining in the 

equipment (if the final pressure of the 

equipment exceeded 0.068 psia).121 We 

are proposing to limit the mathematical 

adjustment approach to situations 

where the measured temperaturecompensated pressure is equal to or 

greater than 90 percent of the design 

operating pressure to ensure that 

nameplate capacity measurements and 

calculations remain precise. If smaller 

fractions of the full charge are scaled up 

to calculate the nameplate capacity, the 

uncertainty of the calculation begins to 

approach (and ultimately exceed) two 

percent given the precision and 

accuracy requirements we are proposing 

for pressure gauges and other 

measurement devices. We request 

comment on the expected accuracy of 

the mathematical adjustment approach, 

and whether it should be enhanced to 

account for non-linearities in the 

relationship between pressure and 

density. Our analysis of this issue, 

discussed in the Technical Support 

Document, indicates that such nonlinearities can lead to systematic errors 

in the results of the mathematical 

adjustment approach under some 

circumstances. One way of addressing 

such non-linearities would be to include 

a compressibility factor (often termed a 

‘‘Z’’ factor) in the calculation, as we 

have done for gas measurements for 

other subparts (see, e.g., equation I–25 

of subpart I (Electronics Manufacturing) 

and equation L–33 of subpart L 

(Fluorinated Gas Production) of part 98). 

A version of equation DD–4 including 

compressibility factors is included in 

the Technical Support Document. 

The mathematical adjustment 

approach would accommodate 

situations where it may not be possible 

to fully recover the insulating gas from 

the equipment, e.g., where the 

equipment has leaks through which air 

would be drawn into the equipment and 

subsequently into the recovery 

equipment or gas cart if the equipment 

were drawn into a deep vacuum. 

However, as discussed further in the 

Subpart DD TSD, an inability to pull the 

equipment into a vacuum may lead to 

inaccurate nameplate capacity 

measurements unless the accuracy and 

precision requirements for pressure 

gauges are tightened beyond those in the 

proposed rule. We request comment on 

this issue and on alternative methods 

for addressing nameplate capacity 

measurements for equipment with large 

leaks. For example, CARB has adopted 

an exception to its nameplate capacity 

measurement requirements for 

equipment with ‘‘compromised 

integrity.’’ The mathematical adjustment 

approach would also avoid some of the 

disadvantages of the charge adjustment 

approach, which, compared to the 

mathematical adjustment approach, 

would be more time-consuming and 

risks emitting more insulating gas and 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37005 

122State of California Air Resources Board, 

‘‘Notice of Public Availability of Modified Text: 

Proposed Amendments to the Regulation for 

Reducing Sulfur Hexafluoride Emissions from Gas 

Insulated Switchgear,’’ May 5, 2021, and State of 

California Air Resources Board, ‘‘Notice of Public 

Availability of Modified Text: Proposed 

Amendments to the Regulation for Reducing Sulfur 

Hexafluoride Emissions from Gas Insulated 

Switchgear,’’ June 17, 2021. Available at https://

ww2.arb.ca.gov/rulemaking/2020/sf6?utm_

medium=email&utm_source=govdelivery. 

contaminating the insulating gas used to 

top up the equipment with impurities in 

the gas that remains in the equipment. 

To ensure that the mass-balance 

method is based on consistent 

nameplate capacity values throughout 

the life of the equipment, we are 

proposing at 40 CFR 98.303(b)(9) that 

electrical equipment users would be 

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). 

Currently, subpart DD requires that 

scales used to measure cylinders of gas 

be accurate and precise to within 2 

pounds of true weight and be 

periodically recalibrated per the 

manufacturer’s specifications. Subpart 

DD does not include accuracy or 

precision requirements for other 

measuring devices, such as flow meters, 

pressure gauges, or thermometers. To 

help ensure that electrical equipment 

users obtain accurate measurements of 

their equipment’s nameplate capacities, 

we are therefore proposing at 40 CR 

98.303(b)(10) that electrical equipment 

users use measurement devices that 

meet the following accuracy and 

precision requirements when they 

measure the nameplate capacities of 

new and retiring equipment. 

(1) 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. 

(2) 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. 

(3) Temperature gauges must be 

certified by the manufacturer to be 

accurate and precise to within ±1.0 °F; 

and 

(4) Scales must be certified by the 

manufacturer to be accurate and precise 

to within one percent of the true weight. 

These requirements are the same as 

those proposed by CARB in its May 5, 

2021 and June 17, 2021 documents,122

except we are clarifying that the 

measurement devices must be precise as 

well as accurate. The measurement 

devices listed here would be subject to 

the general GHGRP calibration 

requirements at 40 CFR 98.3(i). 

Even if electrical equipment users use 

an accurate thermometer, they may 

under- or overestimate the temperature 

of the gas being filled into the 

equipment or recovered from it, for 

example if they assume that the gas is 

at the same temperature as the area 

surrounding the equipment. This is 

because gas that is filled into equipment 

from a container may be cooler or 

warmer than the ambient temperature 

depending on the method used to 

transfer the gas. Where the insulating 

gas is pulled from the container in the 

liquid phase, an evaporator is generally 

used between the container and the 

equipment to ensure that only gas is 

transferred into the electrical 

equipment. A representative of a gas 

cart manufacturer indicated that the gas 

transferred using this method is often 

slightly warmer than the ambient 

temperature. In this case, the density of 

the gas will be lower than the density 

calculated using the ambient 

temperature. Where the insulating gas is 

pulled from the container in the gas 

phase, the container (and the gas inside) 

tends to cool as the gas boils off from 

a reservoir of liquid insulating gas in the 

container. Heating blankets are often 

used to warm the container and gas in 

this case, but they may not compensate 

for the temperature loss associated with 

the phase change. In this case, the gas 

will be cooler than the ambient 

temperature, and its density will be 

higher than the density calculated using 

the ambient temperature. To at least 

partly address these issues, we are 

proposing to require that equipment 

users measure the temperature of the 

electrical equipment rather than relying 

on the ambient temperature when 

making nameplate capacity 

measurements. However, even 

measurements on the surface of the 

electrical equipment may not reflect the 

temperatures inside, at least not right 

away. To ensure that the temperature of 

the gas is not under- or overestimated, 

we are considering requiring a 

minimum temperature equilibration 

time following the gas filling procedure. 

We request comment on this option, 

including on what appropriate waiting 

times would be for temperature 

equilibration for equipment of different 

sizes and on whether manufacturer 

filling directions adequately address 

temperature measurement issues. 

Temperature equilibration times that we 

are considering range from 30 minutes 

for relatively small equipment to 8 to 24 

hours for large equipment. 

We also request comment on whether 

it would be sufficient to require that any 

gas inside hoses is ‘‘accounted for’’ both 

before and after equipment filling or 

emptying processes, or whether we 

should specify a more detailed 

procedure for evacuating hoses before 

and after equipment filling and 

emptying. A representative of a gas cart 

manufacturer who commonly provides 

training on use of its gas carts described 

the following procedure to the EPA: 

Any gas in the hoses should be pulled 

back into the gas cart/cylinders before 

the filling or emptying process begins, 

and the baseline measurements on 

scales and/or flow meters should be 

taken at that point. Then the equipment 

should be filled or emptied, the hoses 

should be isolated from the equipment, 

and any remaining gas in the hoses 

should be pulled back into the gas cart/ 

cylinders. At that point the final 

measurements on scales and/or flow 

meters should be taken. We request 

comment on whether we should require 

use of this procedure or whether there 

may be other acceptable procedures for 

ensuring that any gas in hoses is 

accounted for in nameplate capacity 

measurements. 

We are proposing at 40 CFR 98.307(b) 

to require 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 temperatureadjusted pressures of the equipment), 

and whether or not the measured 

nameplate capacity value was adopted 

for that piece of equipment. In addition, 

we are proposing at 40 CFR 98.306(o) 

and (p) to require 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. Collecting 

this information would help enable us 

to ascertain the average magnitude of 

nameplate capacity adjustments at both 

the facility and U.S. level, providing 

insight into the extent to which 

manufacturer-assigned nameplate 

capacities may err and alerting us to 

situations where adjustments are 

unusually large, which may indicate 


jspears on DSK121TN23PROD with PROPOSALS2
37006 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

123The current threshold is based on the total 

nameplate capacity of SF6 or PFC containing 

equipment located within the facility and SF6 or 

PFC containing equipment that is not located 

within the facility but is under common ownership 

or control. 

124See U.S. EPA. Subpart DD Technical Support 

Document—Use of Electric Transmission and 

Distribution Equipment, November 2010. Available 

at https://www.epa.gov/sites/production/files/2015- 

03/documents/subpartdd-tsdelectricpowerequip.pdf and in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

125 Id. The leak rate was originally based on 1999 

weighted leak rates from 42 entities reporting to the 

EPA’s SF6 Emission Reduction Partnership for 

Electric Power Systems. 126Calculated based on beginning of year 

nameplate capacity and total reported emissions to 

subpart DD of 40 CFR part 98, Use of Electric 

Transmission and Distribution Equipment, 

Envirofacts, downloaded from https://

www.epa.gov/enviro/greenhouse-gas-customizedsearch on July 8, 2020. 

127For more information see, Technical Support 

for Proposed Revisions to Subpart DD (2021), 

available in the docket for this rulemaking (Docket 

Id. No. EPA–HQ–OAR–2019–0424). 

that equipment users are not following 

the procedures specified in the rule to 

ensure that they measure nameplate 

capacity values accurately. 

2. Proposed Revisions To Streamline 

and Improve Implementation for 

Subpart DD 

In alignment with our proposed 

revisions to include additional F–GHGs 

in the source category, and for the 

reasons described in section II.B.1 of 

this preamble, we are proposing to 

revise the applicability threshold of 

subpart DD at 40 CFR 98.301. Subpart 

DD currently requires reporting from 

facilities with a total nameplate capacity 

of SF6 and PFC-containing equipment 

located within the facility or under 

common ownership or control 

exceeding 17,820 pounds. The EPA 

established the nameplate capacity 

threshold 123 of 17,820 pounds in the 

2010 Final Rule for Additional Sources 

of Fluorinated GHGs(75 FR 74774) as an 

‘‘equivalent threshold’’ that 

approximated the 25,000 metric tons of 

CO2 threshold for emissions. Emissions 

of SF6 and PFC from the source category 

include emissions from equipment leaks 

and venting from gas-insulated 

substations and switch gear. The 

insulating gas can also be released 

during equipment manufacturing, 

installation, normal operation and 

maintenance, and disposal. We initially 

chose a nameplate capacity-based 

threshold because nameplate capacity is 

strongly correlated with SF6 emissions, 

and a capacity-based threshold allows 

potential sources to determine whether 

they are above or below the threshold 

more quickly and with less effort than 

through estimating emissions.124 The 

threshold of 17,820 pounds was 

estimated using the GWP of SF6 that 

was applicable at the time and historical 

leakage data reported by industry 

owners and operators who are partners 

in EPA’s SF6 Emission Reduction 

Partnership for Electric Power Systems. 

To help ensure that the GHGRP data 

collected better reflects the emission 

rates and insulating gases that prevail in 

the current electric power system 

industry, we are proposing to replace 

the existing nameplate capacity 

threshold with an emissions threshold 

of 25,000 metric tons CO2e per year of 

F–GHGs. To calculate their F–GHG 

emissions for comparison with the 

threshold, electrical equipment users 

would use one of two new equations in 

subpart DD at 40 CFR 98.301, proposed 

equations DD–1 and DD–2. The 

proposed 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. The equations would 

therefore account for additional 

fluorinated gases (including GHG 

mixtures) now being marketed to the 

industry as well as lower reported 

emission rates within the industry.125

The current nameplate-capacity based 

threshold was based on the historical 

emission rate, which was estimated at 

approximately 13 percent, and the GWP 

for SF6. For small facilities (total 

nameplate capacity between 17,000 and 

50,000 lbs), the largest emission rate 

reported since 2013 (based on beginning 

of year capacity) was 10.3 percent.126

Additionally, some facilities within this 

industry sector may have begun to use 

lower GWP F–GHGs, which is not 

reflected when using only nameplate 

capacity of the equipment to determine 

applicability. Therefore, the current 

nameplate capacity threshold may 

require facilities with annual subpart 

DD emissions below 25,000 mtCO2e per 

year to report. Revising the reporting 

threshold to account for lower emission 

rates and the use of F–GHGs with lower 

GWPs would reduce burden for those 

electric power systems and facilities 

that have decreased their reliance on 

SF6-insulated equipment and would 

maintain a threshold equivalent to the 

25,000 mtCO2e threshold. 

As discussed in section III.N.1 of this 

preamble, we are proposing to revise the 

existing calculation, monitoring, and 

reporting requirements of subpart DD to 

require reporting of additional F–GHGs 

beyond SF6 and PFCs. Therefore, the 

proposed new equations DD–1 and DD– 

2 that we are proposing for the 

applicability threshold would require 

potential reporters to account for the 

total nameplate capacity of all F–GHG 

containing equipment (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 have determined that the 

proposed threshold methodology is 

more appropriate because it represents 

the actual fluorinated gases used by a 

reporter, accounts for gas mixtures, and 

updates the contemporaneous emission 

rate performance for the industry.127

Finally, we are proposing harmonizing 

changes in multiple subsections to 

renumber existing equation DD–1 and 

maintain cross-references to the 

equation. 

The proposed revisions would also 

streamline the reporting requirements to 

focus Agency resources on the 

substantial emission sources within the 

sector and would exclude new electric 

power systems and other new facilities 

from subpart DD when their emissions 

of insulating gas were estimated to be 

below 25,000 mtCO2e per year. The 

proposed changes would revise the 

existing threshold in 40 CFR 98.301 and 

Table A–3 to subpart A (General 

Provisions). Reporters would continue 

to determine the applicability of subpart 

DD under 40 CFR 98.2(a)(1), which 

applies to source categories listed in 

Table A–3, such that only total 

estimated emissions from F–GHGs 

would be accounted for in determining 

whether the applicability threshold is 

met. Therefore, facilities would 

continue to determine the applicability 

of subpart DD without consideration of 

the combined emissions from stationary 

fuel combustion sources (subpart C), 

miscellaneous use of carbonates 

(subpart U), and other applicable source 

categories towards the threshold. 

Due to the definition of ‘‘facility’’ for 

electric power systems that is different 

from the definition of ‘‘facility’’ (in 

subpart A of part 98) that covers 

facilities in other subparts, electric 

power systems always report to the 

GHGRP as unique facilities (i.e., 

emissions from other sources covered by 

the GHGRP that may have overlap in 

location with a subpart DD facility are 

reported under a different e-GGRT 

identifier due to the different definition 

of ‘‘facility’’). Thus, placement of 

subpart DD in Table A–3 or Table A–4 

of subpart A has no effect on the 

emissions considered when determining 

applicability for electric power systems 

if an equivalent threshold is used. 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37007 

128U.S. EPA. Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990–2019 (EPA 2021), 

available at: https://www.epa.gov/ghgemissions/ 

inventory-us-greenhouse-gas-emissions-and-sinks1990-2019. 

129See Technical Support for Proposed Revisions 

to Subpart DD (2021), available in the docket for 

this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. 

However, for other facilities that use 

electrical equipment, it is possible to 

add emissions under subpart DD to 

those from other subparts as they use 

the standard definition of ‘‘facility’’ in 

Subpart A. We are currently proposing 

to maintain subpart DD in Table A–3 of 

subpart A. By keeping subpart DD in 

Table A–3, we expect to continue to 

capture the majority of annual 

emissions from the use of electrical 

transmission and distribution 

equipment (approximately 65 percent in 

2019; down from a high of 73 percent 

due to some facilities becoming eligible 

to exit the program 128) while not 

significantly increasing burden. Moving 

subpart DD to Table A–4 of subpart A 

would likely have a significant impact 

on the number of reporters subject to 

subpart DD but is unlikely to result in 

a significant increase to the proportion 

of emissions covered by the GHGRP, 

because moving subpart DD to Table A– 

4 would only affect facilities that are not 

electric power systems. Facilities that 

are not electric power systems have 

historically reported emissions 

significantly below 25,000 mtCO2e even 

when the total nameplate capacity at the 

facility was over the current threshold 

of 17,820 lbs.129 One option that we are 

considering is to move use of electrical 

equipment to Table A–4 of subpart A, 

which would require facilities that used 

electrical equipment but that were not 

electric power systems to determine 

applicability according to 40 CFR 

98.2(a)(2). Under this option, facilities 

that used electrical equipment but that 

were not electric power systems would 

be required to add their total estimated 

F–GHG emissions from electrical 

equipment to their combined emissions 

from stationary fuel combustion units, 

miscellaneous uses of carbonate, and all 

other applicable source categories that 

are listed in Table A–3 and Table A–4 

to determine whether the facility emits 

25,000 mtCO2e or more per year in 

combined emissions and whether they 

were required to report under part 98. 

In other words, if the result of this 

calculation exceeded 25,000 mtCO2e, 

they would be required to report their 

emissions from electrical equipment 

even if the F–GHG emissions from such 

equipment, by themselves, were below 

25,000 mtCO2e. We are considering 

requiring more comprehensive reporting 

of emissions from users of electrical 

equipment other than electric power 

systems because comparisons between 

the consumption of SF6 reported to the 

GHGRP by SF6 suppliers have generally 

exceeded the consumption reported by 

(or estimated by the EPA for) SF6 users. 

It is possible that SF6 consumption by 

users of electrical equipment with 

nameplate capacities under the current 

threshold (and therefore with SF6

emissions that are likely to fall under 

the 25,000 mtCO2e threshold) could 

account for some of this gap, and 

therefore it is possible that reporting by 

these facilities would at least partially 

explain the gap. However, we recognize 

that if we move subpart DD to Table A– 

4, numerous facilities that are subject to 

this part because of emissions from 

another source category would 

potentially be newly required to report 

under subpart DD with only a few 

pieces of gas-insulated equipment. One 

option for addressing this concern 

would be not to require reporting when 

emissions from the facility’s electrical 

equipment, as calculated using equation 

DD–2, fell below a threshold, such as 

1,000 mtCO2e. We request comment on 

these options. 

O. Subpart FF—Underground Coal 

Mines 

The EPA is proposing two technical 

corrections to subpart FF of part 98 

(Underground Coal Mines), for the 

reasons described in section II.A.5 of 

this preamble. First, we are proposing to 

correct the term ‘‘MCFi’’ in equation FF– 

3 of subpart FF to revise the term ‘‘1- 

(fH2O)1’’ to ‘‘1-(fH2O)i.’’ The proposed 

change would correct an error 

inadvertently introduced in the 

November 29, 2013 final rule (78 FR 

71967). Second, we are proposing a 

revision to 40 CFR 98.326(t). Facilities 

are required to report the Mine Safety 

and Health Administration (MSHA) 

identification number to the EPA. The 

technical correction would add the 

word ‘‘number’’ after the word 

‘‘identification’’ to clarify the reporting 

requirement. 

P. Subpart GG—Zinc Production 

We are proposing one revision to 

subpart GG of part 98 (Zinc Production) 

that would improve the quality of the 

data collection under the GHGRP. For 

the reasons described in section II.A.4 of 

this preamble, we are proposing to add 

a reporting requirement at 40 CFR 

98.336(a)(6) and (b)(6) for the total 

amount of EAF dust annually consumed 

by all Waelz kilns at zinc production 

facilities. EAF dust and other scrap 

materials are primary inputs at certain 

zinc production and recycling facilities 

from which zinc is recovered. The EPA 

is proposing to collect this data in order 

to improve verification of reported data 

under the GHGRP. This data would also 

improve emissions estimates developed 

as part of the U.S. GHG Inventory. 

Collection of this data would be useful 

for verification of data reported through 

the GHGRP by assisting with data 

validation. The amount of EAF dust 

consumed by facilities strongly 

correlates with process CO2 emissions. 

Therefore, the total amount of EAF dust 

consumed by all Waelz kilns could be 

used for comparison to emissions 

estimates and would be useful for 

verifying consistency in emissions over 

time. Additionally, the U.S. GHG 

Inventory uses Tier 1 methods from the 

2006 IPCC Guidelines to estimate 

emissions from zinc produced. For 

primary zinc production, the inventory 

uses a Waelz kiln emission factor based 

on zinc production for non-EAF dust 

consuming facilities, and a Waelz kiln 

emission factor based on EAF dust 

consumption for EAF-dust consuming 

facilities. Currently, the EPA is only 

able to obtain EAF dust consumed for a 

small number of facilities using Waelz 

kilns, which increases the uncertainty of 

these emission factors. Further, for 

Waelz kiln-based production, the IPCC 

recommends the use of emission factors 

based on EAF dust consumption, since 

the amount of carbonaceous materials 

(e.g., coal or coke) used (which drives 

process CO2 emissions) is more directly 

dependent on the amount of EAF dust 

consumed, rather than the amount of 

zinc produced. Collecting the total 

annual EAF dust consumed for all 

Waelz kilns at facilities would allow the 

EPA to develop a more accurate 

emission factor for facilities using Waelz 

kilns for the Inventory. 

Reporters currently estimate 

emissions using either a CEMS direct 

measurement methodology or calculate 

process CO2 emissions by determining 

annually the total mass of carboncontaining input materials (including 

zinc-bearing material, flux, electrodes, 

and any other carbonaceous materials) 

introduced into each kiln and furnace 

and the carbon content of each material. 

Of these materials, the proposed data 

element would only require segregation 

and reporting of the mass of EAF dust 

consumed for all kilns. Reporters 

currently collect information on the 

EAF dust consumed on a monthly basis 

as part of their existing operations; 

reporters using the mass balance 

methodology collect this data as a 

portion of the inputs to equation GG–1. 

We are not proposing any changes to the 

mass calculation methodology; reporters 


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37008 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

130U.S. EPA, Municipal Solid Waste in the 

United States: 2007 Facts and Figures, 2007. https:// 

archive.epa.gov/epawaste/nonhaz/municipal/web/ 

pdf/msw07-rpt.pdf. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 131 IPCC. Guidelines for National Greenhouse Gas 

Inventories, Volume 5 Waste, 2006. https://

www.ipcc-nggip.iges.or.jp/public/2006gl/. Available 

in the docket for this rulemaking, Docket Id. No. 

EPA–HQ–OAR–2019–0424. 132See Waste Management, Republic Services, 

National Waste & Recycling Association, Solid 

Waste Association of North America, SCS 

Engineers, and Weaver Consulting Group. 

Comments on the 1990–2017 Draft Inventory of U.S. 

Greenhouse Gas Emissions and Sinks EPA–HQ– 

OAR–2018–0853. March 14, 2019. These and other 

similar comments are in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

133The Environmental Research & Education 

Foundation (2019). Analysis of Waste Streams 

Entering MSW Landfills: Estimating DOC Values & 

the Impact of Non-MSW Materials. Retrieved from 

www.erefdn.org. Available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ–OAR–2019– 

0424. 

134U.S. EPA. 2008. AP–42: Compilation of Air 

Emissions Factors, Fifth Edition, Volume 1, Chapter 

2.4: Municipal Solid Waste Landfills. https://

www3.epa.gov/ttn/chief/ap42/ch02/index.html. 

Also available in the docket for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424. 

would 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. Therefore, we 

do not anticipate that the proposed data 

elements would require any additional 

monitoring or data collection by 

reporters. The proposed data 

requirement would be required for 

reporters using either the CEMS direct 

measurement or mass balance 

calculation methodologies. We are also 

proposing related confidentiality 

determinations for the additional data 

elements, as discussed in section VI of 

this preamble. 

Q. Subpart HH—Municipal Solid Waste 

Landfills 

For the reasons described in section 

II.A.1 of this preamble, we are 

proposing revisions to subpart HH of 

part 98 (Municipal Solid Waste 

Landfills) that would improve the 

quality of the data collection under the 

GHGRP. First, we are proposing to 

update the factors used in modeling CH4

generation from waste disposed at 

landfills to reflect the increased amount 

of inert materials that are disposed at 

landfills that do not contribute to CH4

generation. The updated factors would 

allow MSW landfills to more accurately 

model their CH4 generation. 

Subpart HH uses a first order decay 

model to estimate CH4 generation from 

MSW landfills. This model 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 

of subpart HH contains 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 

options available under the current rule 

can generally be summarized as follows: 

• The Bulk Waste option assumes a 

single stream of waste coming into the 

facility that contains a mixture of 

organic and inorganic wastes. The 

current default DOC for this waste 

stream is 0.20, and the default decay 

rate values for this bulk waste stream 

are dependent on precipitation rates: 

0.02 for <20 inches of rainfall per year; 

0.038 for 20–40 inches of rainfall per 

year; and 0.057 for >40 inches of rainfall 

per year. 

• The Modified Bulk MSW option 

allows facilities to break out their waste 

into three different streams: bulk MSW 

excluding inert and construction and 

demolition (C&D) wastes (effectively 

‘‘organic MSW’’); C&D waste; and inert 

waste. The decay rates for the ‘‘organic 

MSW’’ stream are the same as those 

listed for the Bulk Waste option, 

however the default DOC is a higher 

value of 0.31. This value was calculated 

from the waste quantities reported in 

the EPA’s ‘‘Municipal Solid Waste in 

the United States: 2007 Facts and 

Figures’’ report 130 specifically for the 

GHGRP considering only the organic 

containing portions of MSW. 

• The Waste Composition option 

provides defaults for DOC and k for 

several subcategories of waste including 

food waste, garden waste, paper waste, 

wood waste, inert waste, etc. The DOC 

and k values for different subcategories 

of wastes are based on the values 

recommended in the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories, Volume 5 Waste, Chapters 

2 and 3.131 Reporters are allowed to use 

the waste composition option for those 

waste streams for which compositional 

data are available and use the bulk 

waste defaults (DOC and k values as 

described in the Bulk Waste option 

above) for waste streams where 

compositional data are not available. 

The EPA has received comments from 

stakeholders in the waste industry (i.e., 

Waste Management, Republic Services, 

National Waste & Recycling Association, 

Solid Waste Association of North 

America, SCS Engineers, and Weaver 

Consulting Group) related to the values 

for DOC and k for both the Bulk Waste 

and Modified Bulk Waste Options listed 

under Table HH–1 to subpart HH. These 

comments 132 were received during the 

expert and public comment review 

period for the U.S. GHG Inventory. The 

U.S. GHG Inventory for solid waste uses 

directly reported emissions values from 

subpart HH to estimate national CH4

emissions from MSW landfills 

throughout the entire United States, and 

the commenters noted that, in order to 

implement these suggested revisions to 

the U.S. GHG Inventory, revisions must 

first be made to subpart HH. 

Commenters argued, based on alleged 

fundamental shifts in the 

characterization of waste disposed in 

landfills and research conducted by 

state agencies and the Environmental 

Research and Education Foundation 

(EREF),133 that: (1) the default DOC 

values for Bulk Waste and Modified 

Bulk Waste overestimate the organic 

fraction of waste in U.S. landfills and 

therefore overestimate emissions from 

this source; and (2) that the EPA should 

perform an analysis of data reported to 

subpart HH and update the default k 

values as necessary based on the results 

of this analysis. Commenters noted that 

the default values for k currently listed 

in Table HH–1 of subpart HH for both 

the Bulk Waste and Modified Bulk 

Waste options are based on data from 

the EPA’s 2008 draft AP–42: 

Compilation of Air Emissions Factors 134

(which is still in draft form) and stated 

these default values are likely out-ofdate considering changes in waste 

disposal trends in the past two decades. 

In response, the EPA performed a 

multivariate analysis to minimize the 

difference between CH4 generation 

estimates back-calculated from the 

reported values of equation HH–7 and 

the CH4 generation predicted using 

equation HH–1, while optimizing k and 

DOC simultaneously for each landfill 

included in the analysis cohort. Six 

years of GHGRP data for 355 landfills 

were ultimately analyzed in this cohort. 

These 355 landfills were subpart HH 

reporters that reported a gas collection 

system (GCS) installed on-site for all 

reporting years, reported a consistent 

waste categorization option for all 

reporting years, and reported the same 

DOC and decay rate values for all 

reporting years. 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. 

After consideration of the comments 

received and the multivariate analysis 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37009 

135U.S. EPA. 2015. Advancing Sustainable 

Materials Management—2015 Tables and Figures: 

Assessing Trends in Material Generation, Recycling, 

Composting, Combustion with Energy Recovery and 

Landfilling in the United States July 2018, available 

at: https://www.epa.gov/facts-and-figures-aboutmaterials-waste-and-recycling/advancingsustainable-materials-management. Data set from 

1960 to 2015 (see ‘‘Materials_Municipal_Waste_

Stream_1960_to_2015.xlsx’’) available in the docket 

for this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424). 

136See memorandum from Jeff Coburn, RTI 

International, to Rachel Schmeltz, EPA, Modified 

Bulk MSW Option Update, June 18, 2019, available 

in the docket for this rulemaking, Docket Id. No. 

EPA–HQ–OAR–2019–0424). 

137See memorandum from Kate Bronstein and 

Meaghan McGrath, RTI International to Rachel 

Schmeltz, EPA, Comparison of U.S. Inventory 

Waste Model Decay Rate (k) Values to Other 

UNFCCC Annex 1 Country Defaults and Countryspecific Waste Models (June 18, 2019), available in 

the docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

performed, we are proposing to amend 

subpart HH to provide revised DOC and 

k values that would more accurately 

estimate GHG emissions from the MSW 

landfills. We are proposing to amend 

the bulk waste DOC value in Table HH– 

1 from 0.20 to 0.17, which was the 

average optimal DOC value for all 

landfills reporting under the Bulk Waste 

option (n=239) in the multivariate 

analysis. This value is similar to the 

proposed bulk waste DOC value of 0.161 

the waste industry has cited within their 

comments as a result of study produced 

by the EREF (2016). We are proposing 

to use the results of the multivariate 

analysis in lieu of using the EREF 

recommended DOC value because the 

multivariate analysis is more nationally 

representative. EREF develop their 

recommended DOC value using statelevel data for a single year (2013) for 14 

states. The multivariate analysis based 

on subpart HH reported data uses 

facility-level data covering 41 states 

over the course of 6 years (2012–2017). 

It was not possible to use the 

multivariate analysis to develop an 

optimal DOC value for bulk MSW waste 

without inerts and (C&D) waste for the 

Modified Bulk Waste option due to a 

lack of reporters that used this option 

meeting the criteria developed and 

noted above for the multivariate 

analysis. Instead, we reanalyzed the 

DOC value for this option using the 

same approach used to develop this 

factor initially but with updated MSW 

composition data from 2011 to 2015 as 

reported by the EPA.135 The average 

DOC value across the 5-year period 

considering all MSW landfilled is 0.17, 

which agrees well with our optimized 

DOC value for bulk MSW from the 

multivariate analysis. After subtracting 

out inerts, the average DOC for MSW 

excluding inerts is 0.27.136 The percent 

reduction of the DOC value for MSW 

excluding inerts is similar to the percent 

reduction in the average DOC for bulk 

MSW as determined from the 

multivariate analysis. Therefore, we are 

also proposing to revise the DOC value 

for the Modified Bulk MSW option in 

Table HH–1 from 0.31 to 0.27. 

The EPA is also proposing to include 

a DOC value for ‘‘Uncharacterized 

MSW’’ within the Waste Composition 

option in Table HH–1. Currently, 

reporters using this option use the DOC 

provided for the Bulk Waste option for 

these uncharacterized waste streams as 

provided in 40 CFR 98.343(a)(2). A 

multivariate analysis of the facilities 

that use a hybrid approach of the Waste 

Composition option and the Bulk Waste 

option indicates that the optimal DOC 

value for uncharacterized MSW is much 

greater than the value for bulk DOC. The 

multivariate analysis indicates an 

optimal DOC value for uncharacterized 

DOC when using the waste composition 

option of 0.32. Therefore, we are 

proposing to include within Table 

HH–1 a DOC for uncharacterized MSW 

of 0.32 and proposing to revise 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. Details of this analysis are 

available in the memorandum, 

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, available in 

the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

We note that DOC and k values are 

linked. Appropriate k values are 

primarily dependent on the composition 

of the waste and on the moisture 

content of the waste within the landfill 

(2006 IPCC Guidelines for National 

Greenhouse Gas Inventories, Volume 5 

Waste, Chapter 3), which is why subpart 

HH includes different k values based on 

annual precipitation rates. The 

multivariate analysis we conducted 

determined the optimal values for DOC 

and k values when varying both 

parameters. The optimal DOC value for 

bulk waste would have been higher if 

we had conducted a single variable 

analysis and had used only the k values 

currently provided in Table HH–1. 

Because of this linkage between the 

DOC and k values, the EPA is also 

proposing to revise the default decay 

rate values in Table HH–1 for both the 

Bulk Waste option and the Modified 

Bulk MSW option and add k value 

ranges for uncharacterized MSW for the 

Waste Composition Option as shown in 

Table 4 of this preamble. The proposed 

defaults represent the average optimal k 

values for the cohort of landfills within 

each precipitation category. The 

proposed k values are larger than the 

current defaults but provide a more 

accurate estimate of the landfill’s 

emissions based on the results of the 

multivariate analysis. We also reviewed 

the k values used in other countries’ 

inventories as well as those 

recommended in the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories. We found that the current 

k values in Table HH–1 were low 

compared to those used in other 

countries with climates similar to that 

in the U.S. We also found that the k 

values we are proposing more closely 

align with those used in countries with 

similar climates to the U.S. and with the 

defaults for moderately decaying bulk 

waste provided in the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories.137 Because our review of 

other inventory k values and our 

multivariate analysis indicate that the 

current k values in Table HH1 are too 

low, we are proposing to revise these k 

values consistent with the results of our 

multivariate analysis and consistent 

with our revision to the default DOC for 

bulk waste. 

TABLE 4—PROPOSED DEFAULT K VALUES

Factor 

Current 

subpart HH 

default 

Proposed 

subpart HH 

default 

Units 

k values for Bulk Waste option and Modified Bulk MSW option 

k (precipitation plus recirculated leachate <20 inches/year) ....................................................... 0.02 0.055 yr¥1 

k (precipitation plus recirculated leachate 20–40 inches/year) ................................................... 0.038 0.111 yr¥1 

k (precipitation plus recirculated leachate >40 inches/year) ....................................................... 0.057 0.142 yr¥1 


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37010 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

138Meaghan 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. 

TABLE 4—PROPOSED DEFAULT K VALUES—Continued 

Factor 

Current 

subpart HH 

default 

Proposed 

subpart HH 

default 

Units 

k value range for Waste Composition option 

k (uncharacterized MSW) ............................................................................................................ Not applicable 0.055 to 0.142 yr¥1 

Altering both the default DOC and k 

values for subpart HH reporters would 

affect closed and open landfills in 

different ways. Implementing the 

recommended, and higher, k values will 

serve to increase the emissions 

calculated from equation HH–1 and 

equation HH–5 for open, active 

landfills. The higher k values imply that 

the organic material that is placed in the 

landfill will degrade more quickly than 

predicted when using lower k-values. 

This tends to lead to greater calculated 

emissions from active landfills (landfills 

actively receiving waste during a 

reporting year). The higher k values also 

tend to predict that less degradable 

waste will be in the landfill once the 

landfill closes (i.e., no longer receives 

wastes) and the degradable waste that is 

present in the closed landfill will 

decompose more quickly. This tends to 

reduce the emissions calculated for 

closed landfills, which may allow 

closed landfills to more quickly phaseout of the reporting program (i.e., when 

reported emissions fall below the 25,000 

mtCO2e threshold for 5 years 

consecutive years). Thus, the proposed 

k values are expected to increase the 

calculated emissions from active 

landfills, reduce calculated emissions 

from closed landfills, and potentially 

reduce burden associated with the 

reporting requirements for closed 

landfills (due to having fewer years of 

reported emissions above the reporting 

threshold once the landfill is closed). 

We also note that the emissions from the 

landfill over its entire life (active and 

closed periods) is dependent only on 

the amount of degradable organic 

material placed in the landfill, which is 

dependent only on the DOC value. 

Thus, the lower DOC value should 

reduce the cumulative emissions 

reported for a given landfill over all 

reporting years; however, it may 

increase the emissions reported during 

the years the landfill is actively 

receiving wastes. 

To determine an estimate of the effect 

of these changes on overall subpart HH 

emissions reporting, equation HH–1 

methane generation from six landfills in 

the final analysis cohort, three closed 

landfills (one in each precipitation 

range) and three open landfills (one in 

each precipitation range), were 

recalculated (as an illustrative example) 

with the recommended DOC value of 

0.17 and the recommended k value 

corresponding to the landfill’s 

precipitation zone.138 On average, the 

selected closed landfills had a 21 

percent decrease in methane generation 

while the selected open landfills saw a 

55 percent increase. These are 

illustrative examples and not a 

quantitative nationwide assessment of 

the impact of the proposed revisions to 

DOC and k values, but they confirm our 

expectations. The nationwide impact of 

these changes will likely be limited to 

a large extent because the large majority 

(approximately 90 percent) of the 

emissions reported under subpart HH 

are from facilities with GCS. Facilities 

with GCS use two different calculation 

methodologies to determine methane 

emissions: equation HH–6, which used 

the predicted methane generation from 

equation HH–1 and the amount of 

methane recovered, and equation HH–8, 

which is based solely on the quantity of 

methane recovered. Per 40 CFR 

98.346(i)(13), facilities with GCS may 

then choose the equation result that best 

represents emissions from the landfill to 

use as their total methane emissions 

reported for subpart HH. About 71 

percent of subpart HH facilities in 

RY2020 used equation HH–8 to estimate 

their methane emissions and the 

proposed revisions would not impact 

the emissions reported for these 

facilities. Thus, the proposed revisions 

would impact only the emissions from 

landfills without GCS and landfills with 

GCS that elect to report emissions using 

equation HH–6, which is a smaller 

fraction (about 35 to 40 percent) of the 

total methane emissions reported 

subpart HH. While methane emissions 

reported by active landfills not using 

equation HH–8 are expected to increase, 

the methane emissions reported by 

closed landfills are expected to 

decrease, and the total amount of 

methane reported to be generated by a 

given landfill over its entire life is 

expected to decrease (based on the 

proposed lower DOC value). 

For the reasons described in section 

II.A.4 of this preamble, we are 

proposing a reporting requirement for 

landfills with gas collection and control 

systems to inform the development of 

GHG policies and programs by 

providing information on the proportion 

of landfill gas used in energy recovery 

projects. There is no anticipated 

significant change in burden due to this 

reporting requirement because key data 

in estimating the annual amount of 

recovered CH4 from data reported by 

measurement location and destruction 

device are already reported. 

Specifically, we are proposing to require 

landfills with gas collection and control 

systems to indicate the percentage of 

recovered CH4 that is sent to a flare or 

sent to a landfill gas to energy project 

for each measurement location. 

For landfills with gas collection and 

control systems, we currently collect the 

following information under 40 CFR 

98.346(i) related to the gas collection 

and control system at the facility: total 

volumetric flow of landfill gas collected 

for destruction, the annual average CH4

concentration of landfill gas for 

destruction, and an indication of 

whether destruction occurs at the 

landfill facility, off-site, or both. For 

landfills where destruction occurs at the 

facility, we also ask for information 

about the measurement location(s) and 

destruction device(s) at the facility. This 

information includes the number of 

destruction devices associated with 

each measurement location, the annual 

operating hours of each measurement 

location and its associated destruction 

devices, and the annual quantity of 

recovered CH4 using equation HH–4 for 

each measurement location. We do not 

collect specific information about 

destruction devices located off-site and 

therefore cannot collect the annual 

quantity of CH4 recovered using 

equation HH–4 at the destruction device 

level for all facilities subject to subpart 

HH. Therefore, we are proposing to 

collect information at the measurement 

location level about the proportion of 

landfill gas that is flared versus sent to 

a landfill gas to energy project. 

Specifically, we are proposing at 40 CFR 


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Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37011 

139CBP Form 7501 is available at the U.S. 

Customs and Border Protection website (https://

www.cbp.gov/trade/programs-administration/entrysummary/cbp-form-7501). 

98.346(i)(6)(i) to require landfills with 

gas collection and control systems to 

indicate the percentage of recovered 

CH4 that is flared or sent to a landfill gas 

to energy project for each measurement 

location. We understand that a facility 

owner or operator may not know the 

exact quantity of recovered CH4 sent offsite for destruction by a flare or landfill 

gas to energy project. Facilities that 

indicate off-site destruction in e-GGRT 

and do not know whether the recovered 

gas sent to the off-site destruction 

device is sent to a flare or landfill gas 

to energy project would be allowed to 

allocate the off-site portion of recovered 

gas into an ‘‘unknown’’ option along 

with an optional text description. 

This information would help inform 

the development of GHG policies and 

programs under the CAA by providing 

information on the amount of recovered 

CH4 that is beneficially used in energy 

recovery projects and will assist in 

verification of net CH4 emissions from 

landfills with gas collection and control 

systems. This new requirement will also 

assist with QA/QC of required inputs 

into the U.S. GHG inventory for MSW 

landfills and will inform EPA, state, and 

local government officials on progress 

towards renewable energy targets and 

GHG emission inventories. 

Additionally, researchers have 

requested this information under the 

U.S. national solid waste inventory. We 

are also proposing related 

confidentiality determinations for the 

new data element, as discussed in 

section VI of this preamble. 

R. Subpart NN—Suppliers of Natural 

Gas and Natural Gas Liquids 

For the reasons discussed in section 

II.B.3 of this preamble, the EPA is 

proposing to streamline reporting 

requirements by eliminating some 

duplicative reporting between subpart 

NN (Suppliers of Natural Gas and 

Natural Gas Liquids) and subpart W 

(Petroleum and Natural Gas Systems) by 

eliminating the duplicative elements 

from subpart W, as discussed in section 

III.J.2.f of this preamble. 

S. Subpart OO—Suppliers of Industrial 

Greenhouse Gases 

For the reasons provided in section 

II.A.4 of this preamble, we are 

proposing revisions to subpart OO of 

part 98 (Suppliers of Industrial 

Greenhouse Gases) that would improve 

the quality of the data collection under 

the GHGRP. First, we are proposing to 

add a requirement for bulk importers of 

F–GHGs to include, as part of the 

information required for each import in 

the annual report, the customs entry 

summary number. The customs entry 

summary number is provided as part of 

the U.S. Customs and Border Protection 

(CBP) Form 7501: Entry Summary 139

and is assigned for each filed CBP entry 

for each shipment. We are proposing to 

gather this data, which is already 

available in supplier records, to verify 

and compare the data submitted to the 

GHGRP with other available customs 

data. The proposed customs entry 

summary number would provide a 

means to cross-reference the data 

submitted and would help to ensure the 

accuracy and completeness of the 

information reported under the GHGRP. 

The proposed changes would modify 40 

CFR 98.416(c)(7). Because the 

information collected is readily 

available in supplier records and is 

similar to the identifying information 

currently collected (i.e., date of import, 

port of entry, country, commodity code, 

and importer number), there is no 

anticipated significant change in 

burden. 

Additionally, the EPA is proposing to 

require at 40 CFR 98.416(k) that 

suppliers of N2O, saturated PFCs, and 

SF6 identify the end uses for which the 

N2O, SF6, or PFC is used and the 

aggregated annual quantities of N2O, 

SF6, or each PFC transferred to each end 

use, if known. This requirement, which 

is patterned after a similar requirement 

under subpart PP (Suppliers of Carbon 

Dioxide) of part 98, would help to 

inform the development of GHG policies 

and programs by providing information 

on N2O, SF6, and PFC uses and their 

relative importance. We are proposing 

the requirement for N2O, SF6, and PFCs 

in particular because: (1) the GWPweighted quantities of these compounds 

that are supplied annually to the U.S. 

economy are relatively large; and (2) the 

identities and magnitudes of the uses of 

these compounds are less well 

understood than those of other 

industrial GHGs such as HFCs. For 

example, most N2O is believed to be 

used for anesthetic applications, but the 

exact share used for these applications 

is not known. SF6 is known to be used 

in electrical equipment, magnesium 

production and processing, and 

electronics manufacturing, but the total 

quantity of SF6 that is estimated to be 

consumed by these applications has 

sometimes fallen significantly below the 

total quantity of SF6 supplied annually 

to the U.S. economy from 2011 through 

2019, indicating that significant uses of 

SF6 may not be accounted for. 

Collecting information from suppliers of 

these compounds on how their 

customers use the compounds, and in 

what quantities, would help to resolve 

these questions. 

To inform the revision of the subpart 

OO electronic reporting form in the 

event that this proposed amendment is 

finalized, we request comment on the 

end use applications for which N2O, 

SF6, and saturated PFCs are used and 

their relative importance. The EPA is 

aware of the following end uses of N2O: 

(1) Analgesia or anesthesia, including 

medical, dental, and veterinary uses, 

(2) Oxidizer in fuel, 

(3) Foaming agent (e.g., for use in 

aerosol whipped cream), 

(4) Propellant in aerosol sprays, 

(5) Electronics manufacturing, 

including manufacturing of 

semiconductors (including lightemitting diodes), micro-electromechanical systems, liquid crystal 

display, and photovoltaic cells. 

The EPA is aware of the following end 

uses of SF6: 

(1) Electrical equipment use (i.e., by 

electric transmission and distribution 

systems), 

(2) Electrical equipment 

manufacturing, 

(3) Electronics manufacturing, 

including manufacturing of 

semiconductors (including lightemitting diodes), micro-electromechanical systems, liquid crystal 

display, and photovoltaic cells, 

(4) Magnesium production and 

processing, 

(5) Dielectrics for particle 

accelerators, including university and 

research particle accelerators, industrial 

particle accelerators, and medical 

particle accelerators, 

(6) Radar systems, 

(7) Adiabatic uses, including use in 

shoe soles and car tires, 

(8) Sound-proof windows, 

(9) Tracer gas, including leak 

detection, 

(10) Waterproofing (e.g., of textiles 

and/or circuit boards), 

(11) Other medical applications. 

The EPA is aware of the following end 

uses of saturated PFCs: 

(1) Electronics manufacturing, 

including manufacturing of 

semiconductors (including lightemitting diodes), micro-electromechanical systems, liquid crystal 

display, and photovoltaic cells, 

(2) Heat transfer fluids, 

(3) Electrical equipment use, 

(4) Electrical equipment 

manufacturing, 

(5) Adiabatic uses, including use in 

shoe soles and car tires, 

(6) Cosmetic applications, 

(7) Medical applications, 


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140A complete list of codes and current HTS 

Chapters can be found at https://hts.usitc.gov/ 

current. 

141The definition of DAC was added to the CAA 

as part of the Utilizing Significant Emissions with 

Innovative Technologies Act (USE IT Act), which 

was included in Section 102 of Division S of the 

Consolidated Appropriations Act, 2021, available at 

https://www.congress.gov/116/bills/hr133/BILLS116hr133enr.pdf. 

(8) Waterproofing (e.g., of textiles 

and/or circuit boards). 

We request comment on the above list 

and any additional end-uses of GHGs 

that should be considered for inclusion 

in the reporting form. 

Finally, we are proposing a 

clarification to the reporting 

requirements for importers and 

exporters of F–GHGs, F–HTFs, or N2O, 

for the reasons provided in section 

II.A.5 of this preamble. We are 

proposing 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. Importers and 

exporters currently provide the 

commodity code as part of the annual 

summary information provided for each 

import or export at the corporate level. 

The majority of reporters provide a 

commodity code based on codes 

assigned through the HTS, which 

assigns 10-digit codes to identify 

products that are unique to U.S. 

markets. HTS codes start with a 6-digit 

code specifying a chapter, heading, and 

subheading, and in full include a 

specific 10-digit code including a 

subheading for duty and a statistical 

suffix. However, in some cases the 

requirement has apparently been 

unclear to and misread by reporters, and 

reporters may identify shipments using 

other commodity code systems, such as 

the abbreviated 6-digit codes assigned 

by the international Harmonized System 

(HS) or Standard Industrial 

Classification System (SIC), or may 

enter other unidentifiable data into the 

‘‘commodity code’’ field. Reporters may 

also enter the data in different formats 

(e.g., with or without decimals). This 

has resulted in cases in which the data 

provided in some annual reports is 

unclear or unable to be compared to 

outside data sources for verification. In 

order to reduce confusion for reporters 

and standardize the data received we 

are proposing to replace ‘‘commodity 

code’’ with ‘‘Harmonized Tariff System 

code’’ in 40 CFR 98.416(c)(6) and 40 

CFR 98.416(d)(4). Reporters would enter 

the full 10-digit HTS code with 

decimals, to extend to the statistical 

suffix, as it was entered on related 

customs forms. For example, in 2020, 

the entry for ‘‘1,1,1,2-Tetrafluoroethane 

(HFC–134a)’’ would be 

‘‘2903.39.20.20’’.140 The proposed 

clarifications would reduce the 

uncertainty associated with the reported 

data elements and improve data 

verification. 

We are also proposing related 

confidentiality determinations for the 

new and revised data elements, as 

discussed in section VI of this preamble. 

T. Subpart PP—Suppliers of Carbon 

Dioxide 

For the reasons discussed in section 

II.A.3 of this preamble, the EPA is 

proposing several revisions to subpart 

PP of part 98 (Suppliers of Carbon 

Dioxide) to improve the quality of the 

data collected from this subpart. 

Subpart PP is intended to identify and 

quantify supplies of CO2 to commercial 

applications, underground injection, or 

geologic sequestration. Subpart PP 

currently requires reporting of the 

annual quantities of CO2 supplied by 

pipeline and in containers from natural 

sources (i.e., extraction wells), capture 

sources, and importers/exporters. 

Capture sources include natural gas 

processing plants, ethanol 

manufacturing facilities, and other types 

of facilities where CO2 is captured and 

supplied for commercial applications or 

to inject or sequester underground. 

Direct air capture (DAC) is a new, 

innovative approach to capturing CO2

from ambient air. Unlike conventional 

capture sources where CO2 is separated 

during the manufacturing or treatment 

phase of product stream, DAC captures 

CO2 from ambient air. CO2 is separated 

from air using aqueous or solid sorbents 

and then processed into a concentrated 

stream for utilization or injection 

underground. Historically a niche or 

experimental technology, interest in 

deploying DAC technology has grown 

significantly in recent years as a 

technology to address climate change. 

We are proposing to add a new 

paragraph 40 CFR 98.420(a)(4), to 

explicitly include DAC as a capture 

option. In addition, we are proposing to 

amend 40 CFR 98.6, to include a 

definition for DAC. Specifically, we are 

proposing 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 definition is taken 

directly from the definition of DAC in 

the CAA at 42 U.S.C. 

7403(g)(6)(B)(III).141 We believe these 

clarifications will benefit owner/ 

operators of DAC facilities, the public, 

and other stakeholders by removing any 

questions or uncertainty about the 

applicability of subpart PP to DAC. 

Moreover, the proposed amendments 

will improve data quality by clarifying 

applicability of subpart PP, thereby 

ensuring the GHGRP accounts for a 

growing and potentially large 

component of the CO2 supply chain. 

To ensure consistency among 

definitions applicable to subpart PP, we 

are also proposing to amend the 

definition of ‘‘Carbon dioxide stream’’ 

in 40 CFR 98.6 to include DAC in the 

definition. Specifically we are 

proposing 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 also proposing to amend other 

sections of subpart PP to explicitly 

include DAC as a capture source for 

consistency with the proposed changes 

to 40 CFR 98.420 and 40 CFR 98.428. 

Specifically, we are proposing to amend 

the following sections to add references 

to DAC: 40 CFR 98.422; 40 CFR 98.423; 

40 CFR 98.426; and 40 CFR 98.427. 

In addition to these changes, we are 

proposing one additional reporting 

requirement in 40 CFR 98.426 to 

improve data quality with respect to 

DAC facilities. Life Cycle Analysis 

(LCA) has become a very important tool 

in determining the net impact of DAC 

projects. DAC processes potentially 

require substantial quantities of energy 

to capture, process and supply CO2; 

therefore, we believe it is important for 

the public and the EPA to understand 

the sources and amounts of energy used 

by DAC facilities to power the DAC 

plant from air intake at the facility 

through custody transfer of captured 

CO2 or, if the CO2 does not leave the 

facility, injection of captured CO2. We 

are proposing to add a new requirement 

at 40 CFR 98.426(i) to require DAC 

facilities to report the amounts of on-site 

and off-site sourced electricity, heat and 

combined heat and power used to 

power the DAC plant from air intake at 


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142The 10 percent emission rate was based on the 

average of ‘‘ideal’’ and ‘‘realistic’’ manufacturing 

emission rates (4 percent and 17 percent, 

respectively) identified in a paper prepared under 

the auspices of the International Council on Large 

Electric Systems (CIGRE) in February 2002 

(O’Connell, P., F. Heil, J. Henriot, G. Mauthe, H. 

Morrison, L. Neimeyer, M. Pittroff, R. Probst, J.P. 

Tailebois (2002) SF6 in the Electric Industry, Status 

2000, Cigre. February 2002.), available at https://

www.epa.gov/sites/default/files/2016-02/ 

documents/conf02_pittroff.pdf and in the docket for 

this rulemaking, Docket Id. No. EPA–HQ–OAR– 

2019–0424. This method for estimating OEM 

emissions was the same method used in EPA’s 

Inventory of Greenhouse Gas Emissions and 

Sinks:1990–2006 (EPA 2008). Available at: https:// 

www.epa.gov/ghgemissions/inventory-usgreenhouse-gas-emissions-and-sinks-1990-2006 

(accessed September 15, 2021). 

the facility through the point of 

compressed CO2 stream ready for 

supply for commercial applications or, 

if maintaining custody of the CO2

stream, sequestration or injection of the 

CO2. In addition, for on-site sourced 

electricity, heat and combined heat and 

power, we are proposing that DAC 

facilities indicate whether flue gas is 

also captured by the DAC process unit. 

We are additionally proposing related 

confidentiality determinations for the 

new data elements, as discussed in 

section VI of this preamble. 

U. Subpart SS—Electrical Equipment 

Manufacture or Refurbishment 

1. Proposed Revisions To Improve the 

Quality of Data Collected for Subpart SS 

For the reasons discussed in section 

II.A of this preamble, we are proposing 

several revisions to subpart SS of part 

98 (Electrical Equipment Manufacture 

or Refurbishment) to improve the 

quality of the data collected from this 

subpart. Currently, this subpart requires 

reporting of emissions from 

manufacturing and refurbishing 

processes that include SF6 and PFCs. 

We are proposing to revise the existing 

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. As 

discussed in section III.N of this 

preamble, although SF6 and PFCs have 

been the most commonly used 

insulating gases in the electrical power 

industry, over the implementation of the 

reporting program the EPA has become 

aware of alternative technologies and 

replacements for SF6, including 

fluorinated gas mixtures. Therefore, we 

expect that electrical equipment 

manufacturers and refurbishment 

operations, in addition to electric power 

systems and facilities, include 

equipment or are anticipated to include 

equipment containing these alternative 

gas mixtures (e.g., fluoronitrile or 

fluoroketone mixtures). As such, we are 

proposing revisions to subpart SS in 

order to capture emissions from 

equipment using these alternative gases 

that are not currently accounted for. The 

proposed reporting of these additional 

F–GHGs would improve the accuracy of 

emissions reported under subpart SS 

and enhance the overall quality of the 

data collected under the GHGRP. 

To implement these revisions, we are 

proposing to 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 proposed 

changes would also apply to the 

threshold in 40 CFR 98.451. Under the 

proposed rule, facilities would also 

consider additional F–GHGs purchased 

by the facility in estimating emissions 

for comparison to the threshold. There 

are no known facilities that currently 

use the alternative gas mixtures 

exclusively or in large quantities that 

would render them newly subject to the 

subpart; therefore, we expect the 

proposed changes would result in 

minimal burden for reporters. 

The proposed revisions to subpart SS 

include minor revisions to equations 

SS–1 through SS–6 (which we are 

proposing be renumbered SS–2 through 

SS–7 to accommodate a new equation 

SS–1 as discussed in section III.U.2 of 

this preamble) to incorporate the 

estimation of emissions from all F– 

GHGs within the existing calculation 

methodology, 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 

proposing a definition of ‘‘insulating 

gas’’ and proposing 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 proposed changes do not 

significantly revise the existing 

calculation requirements. Although the 

revisions do require additional 

monitoring and reporting requirements 

(including, but not limited to, the 

tracking of alternative gases in a 

facility’s inventory, purchases of 

alternative gases, and the delivery of 

equipment containing alternative gases), 

there are no known facilities that 

currently manufacture large quantities 

of electrical transmission and 

distribution equipment that use 

alternative gas mixtures in the U.S.; 

therefore, we expect only a minimal 

increase in burden due to the collection 

of data for any equipment containing F– 

GHGs that are not SF6 or PFCs. 

However, we expect that the use of 

alternative gases will continue to 

increase and collection of this data is 

important to both understand emission 

trends and account for total emissions 

from the sector. Finally, we are 

proposing related confidentiality 

determinations for the revised data 

elements that incorporate additional F– 

GHGs, as discussed in section VI of this 

preamble. 

2. Proposed Revisions to Streamline and 

Improve Implementation for Subpart SS 

For the reasons described in section 

II.B.1 of this preamble, we are proposing 

to revise the applicability threshold of 

subpart SS. The proposed revisions 

would 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 metric tons of CO2 threshold by 

introducing a new equation, equation 

SS–1. To accommodate this new 

equation, we are also proposing minor 

harmonizing changes to renumber 

existing equations SS–1 through SS–6 

and related cross-references. Subpart SS 

currently requires facilities that have 

total annual purchases of SF6 and PFCs 

that exceed 23,000 pounds to report. 

The EPA established the annual 

consumption-based threshold of 23,000 

pounds in the 2010 Final Rule for 

Additional Sources of Fluorinated GHGs 

(75 FR 74774) as an ‘‘equivalent 

threshold’’ that approximated the 

25,000 metric tons of CO2 threshold. 

Emissions of SF6 and PFC from the 

source category include emissions from 

the testing, manufacturing, and 

installation or commissioning of 

equipment, but can also occur when 

equipment is decommissioned at a 

manufacturing facility. The current 

threshold was based on an average 

emission rate estimated at 

approximately 10 percent 142 and the 

GWP for SF6 referenced in the 2009 

Final Rule from the IPCC Second 

Assessment Report. Since that time, the 

GWP for SF6 has been updated in the 

GHGRP to a lower value (78 FR 71904, 

November 29, 2013). Further, some 

facilities within this industry sector 

have begun to use lower GWP F–GHGs, 

which are currently not accounted for in 

subpart SS. Therefore, we are proposing 

to revise the applicability threshold to 

align with the proposed revisions to 

require reporting of additional F–GHG 

beyond SF6 and PFCs. The proposed 

equation SS–1 would continue to be 

based on the total annual purchases of 

insulating gases, but would establish an 

updated comparison to the threshold, 

and would account for the additional 


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fluorinated gases reported by industry. 

Potential reporters would be required to 

account for the total annual purchases 

of all insulating gases, and multiply by 

the GWP for each F–GHG and the 

emission factor of 0.10 (or 10 percent). 

We have determined that the proposed 

threshold methodology is more 

appropriate because it represents the 

actual fluorinated gases used by a 

reporter. The proposed revisions would 

also streamline the reporting 

requirements to focus Agency resources 

on the substantial emission sources 

within the sector. Additionally, the 

proposed changes would revise the 

inclusion of subpart SS in the existing 

Table A–3 to subpart A. Because we are 

proposing to provide a method for direct 

comparison to the 25,000 mtCO2e 

threshold, we are proposing to remove 

subpart SS from Table A–3 and include 

the subpart in Table A–4 of subpart A. 

Including subpart SS in Table A–4 is 

consistent with other GHGRP subparts 

that use the 25,000 mtCO2e threshold 

included under 40 CFR 98.2(a)(2) to 

determine applicability. Currently 

reporters determine the applicability of 

subpart SS under 40 CFR 98.2(a)(1), 

which applies to source categories listed 

in Table A–3. Therefore, facilities 

determine the applicability of subpart 

SS on the basis of the current 

consumption-based threshold without 

consideration of the combined 

emissions from stationary fuel 

combustion sources (subpart C), 

miscellaneous use of carbonates 

(subpart U), and other applicable source 

categories towards the threshold. 

Moving this subpart to Table A–4 of 

subpart A would 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. The change from Table A–3 

to Table A–4 is not expected to result 

in additional reporters under subpart 

SS. Although most facilities subject to 

subpart SS also report under subpart C, 

the reported subpart C emissions are 

typically less than 1000 mtCO2e and are 

not a significant portion of the total 

facility emissions. 

V. Subpart UU—Injection of Carbon 

Dioxide 

The EPA is proposing one amendment 

to subpart UU to ensure consistency 

with new proposed subpart VV 

(Geologic Sequestration of Carbon 

Dioxide with Enhanced Oil Recovery 

Using ISO 27916). Subpart VV is 

described further in section III.W of this 

preamble. The proposed rule change 

adds language to 40 CFR 98.470, 

Definition of the source category, to 

clarify that reporters who report under 

subpart VV for a well or group of wells 

are not required to report under subpart 

UU for that well or group of wells. 

Proposed new 40 CFR 98.470(c) is 

similar to existing language in 40 CFR 

98.470(b) which provides that reporters 

to the Geologic Sequestration of Carbon 

Dioxide source category of the GHGRP 

(subpart RR) for a well or group of wells 

are not required to report under subpart 

UU for that well or group of wells. 

We are proposing this revision to 

reduce the reporting burden on subpart 

VV reporters by eliminating duplicative 

reporting requirements. This proposed 

rule change also improves data quality 

by avoiding double counting of the 

quantities of CO2 received and injected 

at EOR and enhanced gas recovery 

facilities that use the CSA/ANSI ISO 

27916:2019 standard and choose to 

report under subpart VV. This 

avoidance of double counting would 

allow the EPA and the public to better 

track and document the flow of CO2

through the economy. 

In proposing this change, we are also 

proposing to renumber existing 40 CFR 

98.470(c) to 40 CFR 98.470(d); however, 

we are not proposing any rule language 

changes to this paragraph. 

W. Subpart VV—Geologic Sequestration 

of Carbon Dioxide With Enhanced Oil 

Recovery Using ISO 27916 

The GHGRP is proposing to add a new 

subpart—subpart VV—as an option for 

quantifying geologic sequestration in 

association with EOR operations using 

the ISO standard designated as CSA/ 

ANSI ISO 27916:2019, Carbon Dioxide 

Capture, Transportation and Geological 

Storage—Carbon Dioxide Storage Using 

Enhanced Oil Recovery (CO2–EOR). 

Although the title of the standard 

references only EOR, Clause 1.1 of CSA/ 

ANSI ISO 27916:2019 indicates that the 

standard can apply to enhanced gas 

recovery as well. Thus, throughout 

subpart VV, as proposed, any reference 

to EOR also applies to enhanced gas 

recovery. 

Carbon capture, utilization, and 

sequestration (or storage) (CCUS) refers 

to a set of technologies that remove CO2

from the emissions of point sources or 

the atmosphere, and transport it, 

compress it, and inject it deep 

underground, or transform it for 

utilization in industrial processes or as 

feedstock for products. Geologic 

sequestration is feasible in different 

types of geologic formations including 

deep saline formations (formations with 

high salinity formation fluids) or in oil 

and gas formations, where CO2 can be 

injected to increase oil production 

through a process referred to as EOR. 

Subpart RR (Geologic Sequestration of 

Carbon Dioxide) is currently the only 

source category within the GHGRP that 

provides an accounting framework to 

report to the EPA the amount of CO2

geologically sequestered on an annual 

basis. The GHGRP’s geologic 

sequestration data are integral to 

providing transparent information to the 

EPA and the public to track the value 

chain of CO2 supply and disposition. 

The definition of the source category 

for subpart RR includes a well or group 

of wells that inject a CO2 stream for 

long-term containment in subsurface 

geologic formations. It also includes 

wells permitted by the UIC Program as 

Class VI wells. Facilities that conduct 

EOR are not required to report under 

subpart RR unless the owner or operator 

chooses to opt-in to subpart RR, or the 

well is permitted as a Class VI well. An 

operator that does not choose to opt into 

subpart RR must report under subpart 

UU (Injection of Carbon Dioxide) of the 

GHGRP. 

Facilities subject to subpart RR are 

required to develop and implement an 

EPA-approved monitoring, reporting, 

and verification (MRV) plan. The major 

elements of the MRV plan include: (1) 

delineation of active and maximum 

monitoring areas; (2) identification of 

potential surface leakage pathways for 

CO2; (3) a strategy for detecting and 

quantifying surface leakage of CO2; (4) a 

strategy for establishing the expected 

baseline for monitoring CO2 leakage; 

and (5) definition of site-specific 

variables that will be used for estimating 

leakage. Once the facility has an 

approved MRV plan, reporters are 

required to report annually the amount 

of CO2 received, the data used to 

calculate this amount, the source of the 

received CO2 (if known), the mass 

balance equation inputs (amounts of 

CO2 injected, CO2 produced, CO2

emitted by surface leakage, CO2 emitted 

from equipment leaks and vented CO2

emissions), the data used to calculate 

the inputs, and the amount of CO2

sequestered. Facilities are also required 

to submit an annual monitoring report 

which implements the reporting 

requirements set forth in the MRV plan. 

Like subpart RR, subpart UU requires 

facilities to report the quantity of CO2

received, the data used to calculate this 

amount, and the source of the received 

CO2 (if known). However, subpart UU 

does not require an MRV plan or the 

submission of an annual monitoring 

report. Nor does it require monitoring or 

reporting of the fate of the CO2 after the 

custody transfer meter, and thus does 


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143Available at https://www.iso.org/standard/ 

65937.html and in the docket for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424. 144See 26 CFR 1.45Q–0 through 26 CFR 1.45Q– 

5. 145 Internal Revenue Service, Treasury 

Department, Credit for Carbon Oxide Sequestration, 

Final Regulations (88 FR 4728, January 15, 2021), 

available at https://www.govinfo.gov/content/pkg/ 

FR-2021-01-15/pdf/2021-00302.pdf (accessed 

September 7, 2021). 146See 85 FR 34050, 34055 (June 20, 2020). 

not provide an accounting framework of 

the amount of CO2 sequestered. 

In January 2019, ISO published a new 

international standard for CO2 storage 

using EOR. The standard was 

subsequently endorsed by the CSA and 

ANSI and is designated as CSA/ANSI 

ISO 27916:2019, Carbon Dioxide 

Capture, Transportation and Geological 

Storage—Carbon Dioxide Storage Using 

Enhanced Oil Recovery (CO2–EOR)’’.143

The standard establishes a protocol for 

documenting the containment of CO2

injected in an EOR operation and 

quantifying the amount of CO2 that is 

stored in association with that 

operation. 

As part of the Bipartisan Budget Act 

of 2018, Congress revised the Internal 

Revenue Code (IRC) section 45Q tax 

credit for carbon oxide sequestration 

(45Q).144 If a taxpayer meets the 

applicability requirements, section 45Q 

provides tax credits for disposal of 

qualified carbon oxide in secure 

geological storage or utilization. The 

amount of the tax credit for disposal of 

qualified carbon oxide in secure 

geological storage depends on whether 

the qualified carbon oxide is used as a 

tertiary injectant in a qualified 

enhanced oil or natural gas recovery 

project. 

Under a rule finalized by the Treasury 

Department and Internal Revenue 

Service (IRS),145 qualified carbon oxide 

is considered disposed of by the 

taxpayer in secure geological storage 

such that the qualified carbon oxide 

does not escape into the atmosphere if 

the qualified carbon oxide is either: (1) 

injected into a well that complies with 

applicable UIC or other regulations, is 

located onshore or offshore under 

submerged lands within the territorial 

jurisdiction of states or federal waters, 

and is not used as a tertiary injectant in 

a qualified enhanced oil or natural gas 

recovery project; and is stored in 

compliance with applicable 

requirements under subpart RR; or (2) 

injected into a well that complies with 

applicable UIC or other regulations, is 

located onshore or offshore under 

submerged lands within the territorial 

jurisdiction of states or federal waters, 

and is used as a tertiary injectant in a 

qualified enhanced oil or natural gas 

recovery project and stored in 

compliance with applicable 

requirements under subpart RR or CSA/ 

ANSI ISO 27916:2019. 

For EOR facilities that choose CSA/ 

ANSI ISO 27916:2019 for purposes of 

demonstrating secure geological storage 

for the IRC section 45Q tax credit, the 

IRS regulations require that 

documentation be provided to a 

qualified independent engineer or 

geologist, who then must certify that the 

documentation provided, including the 

mass balance calculations as well as 

information regarding monitoring and 

containment assurance, is accurate and 

complete. Under existing GHGRP 

requirements, reporters that choose 

CSA/ANSI ISO 27916:2019 for purposes 

of the section 45Q tax credit continue 

reporting under subpart UU of the 

GHGRP if they choose not to report 

under subpart RR. 

Both subpart RR and CSA/ANSI ISO 

27916:2019 require an assessment and 

monitoring of potential leakage 

pathways; quantification of inputs, 

losses, and storage through a mass 

balance approach; and documentation 

of steps and approaches used to 

establish these quantities. However, the 

inputs of the mass balance equations 

differ as between subpart RR and CSA/ 

ANSI ISO 27916:2019. Specifically, the 

subpart RR mass balance equation for 

quantifying the amount of CO2 that is 

geologically sequestered includes 

variables on injected CO2; equipment 

leaks and vented CO2 emissions from 

surface equipment between the flow 

meters and the wellhead; CO2 produced 

and/or remaining with produced oil, 

gas, or other fluids; and CO2 leakage to 

the surface. In contrast, under CSA/ 

ANSI ISO 27916:2019, 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 CSA/ANSI ISO 27916:2019 

standard defines the EOR complex 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 that are determined under the 

CSA/ANSI ISO 27916:2019 standard 

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. Thus, a primary 

difference between subpart RR and 

CSA/ANSI ISO 27916:2019 relates to the 

terms in their respective mass balance 

equations. 

There are other noteworthy 

differences between subpart RR and 

CSA/ANSI ISO 27916 as well. One is 

how they determine ‘‘leakage.’’ Subpart 

RR quantification is based on leakage of 

CO2 to the surface, that is, emissions of 

CO2 to the atmosphere. In contrast, 

CSA/ANSI ISO 27916:2019 considers 

leakage to be CO2 that migrates outside 

of the EOR complex. 

Another difference is the time when 

facilities may discontinue reporting. 

Under subpart RR, a facility may 

discontinue reporting if it demonstrates 

that current monitoring and model(s) 

show that the injected CO2 stream is not 

expected to migrate in the future in a 

manner likely to result in surface 

leakage. Under CSA/ANSI ISO 

27916:2019, the operator must 

demonstrate that the CO2–EOR project is 

completed, based on (1) the cessation of 

CO2 injection, (2) the cessation of 

hydrocarbon production from the 

project reservoir, and (3) the plugging 

and abandoning of wells, unless 

otherwise required by the appropriate 

regulatory authority. 

Another, and, for present purposes, 

perhaps the most salient difference 

between subpart RR and CSA/ANSI ISO 

27916:2019 is related to public 

transparency. The EPA publishes final 

decisions under subpart RR on its 

website, such as whether to approve an 

MRV plan or request for discontinuation 

of reporting. Any interested person can 

appeal subpart RR final decisions to the 

EPA’s Environmental Appeals Board. In 

addition, the EPA also verifies the data 

submitted in annual GHGRP reports, 

including annual monitoring reports 

submitted under subpart RR, and 

publishes non-confidential data on the 

EPA website. In contrast, facilities that 

follow CSA/ANSI ISO 27916:2019 are 

not currently subject to requirements 

related to public reporting and 

transparency of amounts stored and 

associated documentation. 

In comments to the IRS on the 

proposed IRC section 45Q regulations, 

several commenters supported the IRS’s 

adoption of the CSA/ANSI ISO 

27916:2019 ISO pathway, but were 

concerned that the ISO standard itself, 

as relied on by the IRS, does not contain 

the requirements for public disclosure 

and transparency of information 

necessary to allow the public to review 

the adequacy of the demonstration of 

secure geologic storage. Commenters 

also emphasized the importance and 

need for credible third-party audits and 

certifications, and government oversight 

and enforcement.146 The IRS responded 


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37016 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

147See, e.g., Comments by Carbon Utilization 

Research Council, Clean Air Task Force, ClearPath, 

Environmental Defense Fund, Oxy Low Carbon 

Ventures, Shell Oil Company, and The Nature 

Conservancy on the Proposed ‘‘Credit for Carbon 

Oxide Sequestration,’’ Docket Id. No. IRS–2020– 

0013–0057, August 3, 2020; Comments by Clean Air 

Task Force on the Proposed ‘‘Credit for Carbon 

Oxide Sequestration,’’ Docket Id. No. IRS–2020– 

0013–0035, August 3, 2020; Comments by Shell Oil 

Company on the Proposed ‘‘Credit for Carbon Oxide 

Sequestration,’’ Docket Id. No. IRS–2020–0013– 

0046, August 4, 2020. These comments are in the 

docket for this rulemaking, Docket Id. No. EPA– 

HQ–OAR–2019–0424. 

that it is constrained by law concerning 

the public disclosure of information 

submitted by taxpayers. 

Some stakeholders recommended that 

the EPA promulgate a new subpart to 

the part 98 regulations for GHGRP that 

would establish procedures for 

documenting and reporting the amount 

of carbon oxide securely stored using 

the CSA/ANSI ISO 27916:2019 

methodology.147 The reporting of this 

information to the EPA would ensure 

that the public has access to the relevant 

information in the same manner that the 

public currently has access to the 

information reported to the EPA under 

subpart RR. This reporting would also 

provide the EPA with complete data 

(that is, data from reporting under both 

subpart RR and CSA/ANSI ISO 

27916:2019) to fully understand the 

amounts of CO2 that are geologically 

sequestered for EOR. 

Therefore, the EPA is proposing a new 

source category—subpart VV—related to 

the option for reporting of incidental 

CO2 storage associated with EOR based 

on the CSA/ANSI ISO 27916:2019 

standard. Specifically, facilities that 

conduct EOR would be required to 

report basic information on CO2

received under subpart UU, or they 

could choose to opt-in to either subpart 

RR or the new subpart to quantify 

amounts of CO2 that are geologically 

sequestered. The EPA seeks comment 

on this new proposed subpart VV. 

The EPA is proposing that facilities 

would report the amount of CO2 stored, 

inputs included in the mass balance 

equation used to determine CO2 stored 

using the CSA/ANSI ISO 27916:2019 

methodology, and documentation 

providing the basis for that 

determination as set forth in CSA/ANSI 

ISO 27916:2019. Specifically, the 

reporting of documentation under 

subpart VV would involve providing the 

CSA/ANSI ISO 27916:2019 EOR 

Operations Management Plan (OMP), 

which is required to specify: (1) a 

geological description of the site, 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. The EOR OMP 

sets forth the operator’s approaches for 

containment assurance and monitoring 

and provides the level of detail on 

operations and reporting that are 

comparable to an MRV plan submitted 

under subpart RR. Thus, annual 

reporting under subpart VV should 

specify any changes made to 

containment assurance and monitoring 

approaches and procedures in the EOR 

OMP made within the reporting year. 

In addition, the EPA is proposing that 

reporters annually report the following 

information per CSA/ANSI ISO 

27916:2019: (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 EPA is proposing to require that 

reporters to subpart VV 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. The EPA 

notes that regulations under IRC section 

45Q require the EOR OMP and the data 

in the annual report be provided to a 

qualified independent engineer or 

geologist, who then must certify that the 

documentation, including the mass 

balance calculations as well as 

information regarding monitoring and 

containment assurance, is accurate and 

complete. However, the EPA is not 

proposing EPA approval of a third-party 

approved and certified EOR OMP and 

documentation. In contrast, subpart RR 

requires EPA approval of subpart RR 

MRV plans. 

Under CSA/ANSI ISO 27916:2019, 

monitoring and reporting and associated 

recordkeeping is required to continue 

until the CO2–EOR project is 

terminated, at which time the 

monitoring, reporting, and 

recordkeeping may cease. CSA/ANSI 

ISO 27916:2019 provides that CO2–EOR 

project termination is completed when 

all of the following occur: CO2 injection 

has ceased, hydrocarbon production 

from the project reservoir has ceased, 

and wells have been plugged and 

abandoned unless otherwise required by 

a regulatory authority. The EPA 

proposes that the time for cessation of 

reporting under subpart VV be the same 

as under CSA/ANSI ISO 27916:2019, 

and that the operator notify the 

Administrator of its intent to cease 

reporting and provide a copy of the 

CO2–EOR project termination 

documentation. 

Currently under the GHGRP, if an 

owner or operator chooses to opt in to 

reporting under subpart RR for a CO2– 

EOR project, that owner/operator is no 

longer required to report under subpart 

UU for that CO2–EOR project, in light of 

the fact that CO2 received is reported 

under both subparts. Because CO2

received would be an element in the 

mass balance equation under subpart 

VV for the mass of CO2 input, the EPA 

proposes that if and when an operator 

begins reporting under subpart VV, that 

operator will no longer be required to 

report under subpart UU for that CO2– 

EOR project. 

IV. Additional Requests for Comment 

The EPA is considering future 

revisions to the GHG Reporting Rule to 

potentially expand existing source 

categories or develop other new source 

categories that would add calculation, 

monitoring, reporting, and 

recordkeeping requirements related to 

energy consumption; ceramics 

production; calcium carbide production; 

glyoxal, glyoxylic acid, and caprolactam 

production; coke calcining; and CO2

utilization. Based on our recent review 

of the data collected under the GHGRP 

and in consideration of data that are 

needed to continue to inform the EPA’s 

understanding of GHG data and better 

inform future EPA policy and programs, 

we are considering revising part 98 to 

include these newly identified source 

categories. Therefore, the EPA is 

specifically requesting comment related 

to the potential expansion of existing 

source categories or development of 

new source categories described in this 

section. If the Agency decides that 

sufficient information is available to 

support a rule revision, the EPA may 

consider undertaking a future action to 

expand or add these new source 

categories. 

In the development of the GHGRP, the 

EPA considered its authorities under 

CAA sections 114 and 208 and the 

information that would be relevant to 

the EPA’s carrying out a wide variety of 

CAA provisions when considering 

source categories. As part of the process 

in selecting the original list of source 


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Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37017 

148Refer to the preamble to the April 10, 2009 

proposal (74 FR 16465) for further discussion of the 

EPA’s rationale for its original section of source 

categories to include. 

categories to include in the GHG 

Reporting Rule in 2010, the EPA 

considered the language of the 

Appropriations Act, which referred to 

reporting ‘‘in all sectors of the 

economy,’’ and the accompanying 

explanatory statement, which directed 

the EPA to include ‘‘emissions from 

upstream production and downstream 

sources to the extent the Administrator 

deems it appropriate’’ (74 FR 16465, 

April 10, 2009). To develop the list of 

source categories, we followed a fourstep process: (1) we first considered all 

anthropogenic sources of GHG 

emissions or supply; (2) we considered 

all of the source categories in the U.S. 

GHG Inventory; (3) we reviewed the 

2006 IPCC Guidelines for National 

Greenhouse Gas Inventories for source 

categories that may be relevant for the 

United States; and (4) once the list was 

completed, we systematically reviewed 

those source categories to ensure that 

they included the most significant 

sources of GHG emissions and the most 

significant suppliers of GHG-emitting 

products. We also confirmed that the 

reported GHGs can be measured with an 

appropriate level of accuracy.148 As 

described in sections IV.A through F of 

this preamble, we are requesting 

comment on expanding existing source 

categories or developing other new 

source categories based on the EPA’s 

current understanding of U.S. GHG 

trends and where we have identified 

that additional data may be necessary to 

better understand GHG data from these 

specific sectors to inform future policy. 

The addition of these source 

categories would provide data that 

would help eliminate data gaps, 

improve the coverage of the GHGRP, 

and inform the development of GHG 

policies and programs under the CAA. 

The GHGRP data continues to 

additionally be used as a resource for 

the U.S. GHG Inventory, providing not 

only annual emissions information, but 

also other annual information such as 

activity data and emission factors that 

can improve and refine national 

emission estimates and trends over 

time. Including these additional source 

categories would also allow the EPA to 

gather data that could improve the 

completeness of the emissions estimates 

presented in the U.S. GHG Inventory. 

For example, we are requesting 

comment on whether the EPA should 

collect data on energy consumption, a 

source category for which part 98 does 

not currently require reporting and 

which would support data analyses 

related to informing voluntary energy 

efficiency programs, providing 

information on industrial sectors where 

currently little data is reported to 

GHGRP, and informing QA/QC of the 

U.S. GHG Inventory. Inclusion of certain 

of these source categories would reduce 

potential data gaps in the GHGRP by 

incorporating emission sources that are 

recommended by (and for which there 

are existing calculation methodologies 

available in) the 2006 IPCC Guidelines 

used to prepare the U.S. GHG Inventory. 

Specifically, the IPCC 2006 Guidelines 

currently identify ceramics production, 

calcium carbide production, and 

glyoxal, glyoxylic acid, and caprolactam 

production as potential sources of GHG 

emissions. However, emissions from 

these processes are not currently 

estimated in the GHGRP or the U.S. 

GHG Inventory. The collection of data 

from these source categories (e.g., 

ceramic production, calcium carbide 

production, and glyoxal, glyoxylic acid, 

and caprolactam production) would 

improve the coverage of the GHGRP and 

provide for more accurate estimates of 

U.S. GHG emissions that could then be 

used to inform development of EPA 

policies and programs. 

The EPA is requesting comment on 

some source categories, such as coke 

calciners, that we have identified 

because they may potentially contribute 

significant emissions that are not 

currently reported. In other cases, 

through implementation of the program, 

the EPA has identified facilities 

representative of these source categories 

that are currently reporting under 

another part 98 source category, and 

relying on that other source category’s 

calculation, monitoring, and reporting 

requirements for the purposes of 

estimating total facility GHG emissions. 

However, these facilities may not in fact 

be reporting complete or accurate 

estimates of emissions because 

appropriate estimation methods are 

currently unavailable for the source 

category. We are also requesting 

comment on source categories where we 

have identified emerging industries that 

utilize captured carbon emissions, and 

as a result would improve our 

knowledge of carbon utilization. 

Inclusion of specific requirements for 

these source categories in part 98 would 

provide a means for the EPA to better 

estimate and understand U.S. GHG 

emissions and trends that could inform 

future policies. Therefore, we are 

soliciting comment on these source 

categories and the appropriate 

accounting methodologies, monitoring, 

and associated reporting requirements 

that should be considered in 

development of a future proposed 

rulemaking. Sections IV.A through IV.F 

of this preamble provide additional 

information on the EPA’s consideration 

of including these source categories in 

the GHGRP and the information we are 

seeking. 

The EPA is also considering 

proposing future amendments to 

subpart F of part 98 (Aluminum 

Production) to include reporting for 

additional sources of emissions, to 

update the cell technology types 

reflected in the rule, and to revise or 

replace the measurement and 

calculation methodologies with newer, 

improved methodologies. These updates 

are being considered based on new 

information and methodologies 

identified from the 2019 Refinement. 

Section IV.G of this preamble provides 

additional information on the EPA’s 

consideration of these amendments and 

the information we are seeking. 

A. Energy Consumption 

Indirect GHG emissions can result 

from on-site energy consumption, 

primarily the use of purchased 

electricity and thermal energy products. 

In this preamble we refer broadly to 

purchased electricity and thermal 

energy products such as steam, heat (in 

the form of hot water), and cooling (in 

the form of chilled water) as ‘‘purchased 

energy’’ or as ‘‘purchased energy 

products.’’ These terms expressly 

exclude the purchase of fuels associated 

with direct emissions. 

In the 2009 GHGRP proposal, the EPA 

sought comment on, but did not 

propose, reporting related to electricity 

consumption. See 74 FR 16479, April 

10, 2009. Comments received, as well as 

our responses to those comments, are 

summarized in the 2009 final rule. See 

74 FR 56288–56289, October 30, 2009. 

We note that in 2009 some commenters 

expressed concerns regarding the 

collection of data on purchased 

electricity for several reasons. Primarily, 

they said it would constitute double 

counting if direct emissions were 

collected from electric utilities and the 

EPA also collected electricity 

consumption from facilities and 

estimated emissions attributable to the 

facilities’ electricity consumption. 

Others stated that collecting information 

on electricity purchases was outside the 

scope of the rule, that it is not useful 

information in attempting to quantify 

emissions, that it would be burdensome 

for facilities, and that it is CBI that 

companies are not able to share with the 

EPA. In 2009, we responded to these 

concerns stating that collection of 

electricity purchase data under the 

GHGRP is consistent with the 


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37018 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

149Consolidated Appropriations Act, 2008, Public 

Law 110–161, 121 Stat. 1844, 2128. Congress 

reaffirmed interest in a GHG Reporting Rule, and 

provided additional funding, in the 2009 

Appropriations Act (Consolidated Appropriations 

Act, 2009, Pub. L. 110–329, 122 Stat. 3574–3716). 

150 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. 

151Subpart U of part 98 includes any equipment 

that uses the carbonates limestone, dolomite, 

ankerite, magnesite, siderite, rhodochrosite, or 

sodium carbonate and emits CO2. Facilities are 

considered to emit CO2 if they consume at least 

2,000 tons per year of carbonates heated to a 

temperature sufficient to allow the calcination 

reaction to occur. 

152See U.S. Census Bureau website (https://

www.census.gov/naics/), accessed March 2021. 

153USGS 2020 Mineral Commodity Summaries. 

Clay. U.S. Department of the Interior, U.S. 

Geological Survey, February 2020. https:// 

Consolidated Appropriations 

language,149 and provides valuable 

information to the EPA and stakeholders 

in the development of climate change 

policy and programs. We still believe 

this to be true today. Ultimately, the 

EPA decided at that time not to propose 

requirements for facilities to report 

either their electricity purchases or 

indirect emissions from electricity 

consumption. In the 2009 final 

rulemaking, we stated that acquiring 

such data may be important in the 

future, and we were exploring options 

for possible future data collection on 

electricity purchases and indirect 

emissions and the uses of such data. We 

also said that such a future data 

collection on indirect emissions would 

complement the EPA’s interests in 

energy efficiency and renewable energy. 

In this action, we are requesting 

comment on whether the EPA should 

expand the GHGRP so that facilities that 

are subject to the GHGRP would be 

required to submit new, summary data 

elements quantifying their consumption 

of purchased energy products and 

characterizing associated markets and 

products (e.g., regulated or de-regulated 

electricity markets and renewable 

attributes of purchased products). Under 

this approach, facilities would not be 

required to quantify indirect emissions, 

and indirect emissions would not count 

towards GHGRP applicability. However, 

the EPA could estimate indirect 

emissions using the purchased energy 

data. We solicit comment on this 

potential approach and on advantages 

and disadvantages of limiting the scope 

of any new reporting requirements to 

compiling and reporting purchased 

energy records. 

The EPA is seeking comment on how 

an energy consumption source category 

should be defined, whether it should 

include purchased thermal energy 

products, and whether or not associated 

reporting requirements should 

differentiate purchased thermal energy 

products from purchased electricity. 

The EPA also seeks comment on the 

approach of limiting applicability of an 

energy consumption source category to 

facilities that are currently subject to the 

GHGRP. For example, should the EPA 

consider adding new sector-specific 

requirements for operators of EAFs or 

other operations that may meet all their 

energy needs with purchased power and 

that may not trigger applicability under 

the GHGRP? The EPA is seeking 

comment on specific industrial sectors 

or technologies that may not be 

completely represented within the 

GHGRP but that should be considered 

when evaluating the performance of 

GHGRP sources (including usage of 

purchased energy) within discrete 

sectors. 

The EPA also seeks comment on 

measures that would minimize the 

burden of reporting parameters related 

to purchased energy transactions. The 

EPA understands that cogeneration 

contracts between host facilities and 

energy producers are governed by clear 

metering and billing requirements. 

Accordingly, the EPA is seeking 

comment on our understanding that 

monitoring and recordkeeping systems 

are already in place for purchased 

energy transactions, and the incremental 

reporting burden would be minimal. We 

are also seeking comment on existing 

industry standards for assessing the 

accuracy of the monitoring systems used 

for purchased energy transactions. 

B. Ceramics Production 

The ceramics manufacturing industry 

comprises a variety of products 

manufactured from nonmetallic, 

inorganic materials, many of which are 

clay-based. The major sectors of ceramic 

products include bricks and roof tiles, 

wall and floor tiles, table and 

ornamental ware, 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 general process of manufacturing 

ceramic products consists of raw 

material processing (grinding, calcining, 

and drying), forming, firing, and final 

processing (which may include 

grinding, polishing, surface coating, 

annealing, and/or chemical treatment). 

GHG emissions are produced during 

the calcination process in the kiln or 

dryer and from any combustion sources. 

According to the IPCC 2006 

Guidelines,150 CO2 emissions result 

from the calcination of the raw material 

(particularly clay, shale, limestone, 

dolomite, and witherite) and the use of 

limestone as a flux. Carbonates are 

heated to high temperatures in a kiln or 

dryer, producing oxides and CO2. 

Additionally, CO2, CH4, and N2O 

emissions are produced during 

combustion in the kiln or dryer and 

from other combustion sources on site. 

The EPA is considering future 

amendments to the GHGRP to add a 

source category related to ceramics 

production or to incorporate ceramics 

into an existing subpart. Currently, 

under the GHGRP, ceramic production 

facilities report their GHG emissions 

from stationary fuel combustion sources 

if those emissions exceed the 25,000 

mtCO2e reporting threshold. Some 

ceramic production facilities should 

also report miscellaneous uses of 

carbonate if they meet applicability 

requirements of subpart U of part 98 

(Miscellaneous Uses of Carbonate).151

Addition of a ceramics production 

source category would likely include 

process emissions and would improve 

the EPA’s understanding of facility-level 

emissions from this source category by 

adding to the completeness of the data 

collected under the GHGRP, and better 

inform future EPA policy. Additionally, 

such data would be available to inform 

estimates and improve completeness of 

the U.S. GHG Inventory, consistent with 

methodological guidance and 

completeness principle outlined in the 

2006 IPCC guidelines. 

According to the 2018 United States 

Census Bureau, 815 corporations 

produce ceramic products; 152 however, 

only sixteen facilities owned by nine of 

these corporations reported under 

subpart C of the GHGRP (General 

Stationary Fuel Combustion Sources) for 

RY2019. No ceramics manufacturers 

currently report under subpart U of part 

98. While some ceramics manufacturers 

may use some carbonates directly, it is 

likely the majority of the carbonates 

used are those contained in clay rather 

than pure carbonates. Additionally, 

some ceramic tile kilns may not heat to 

temperatures sufficient for calcination 

to occur, and therefore would not meet 

the applicability requirements of 

subpart U. For these reasons, emissions 

from ceramics manufacturers may not 

be appropriately captured by the current 

part 98. Although the nine corporations 

reported nearly 1 million mtCO2e from 

combustion under subpart C for 

RY2019, we estimate, using United 

States Geological Survey (USGS) 

reports 153 on the tons of clays sold or 


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www.usgs.gov/centers/nmic/mineral-commoditysummaries. 

154 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. 

155 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. 

used in the United States and IPCC 

default emission factor values, that the 

total process CO2 emissions from 

carbonates for all ceramic production 

facilities in the United States is an 

additional 1.16 million mtCO2e. We are 

considering whether adding a ceramic 

production source category, as a 

separate source category or combined 

with either the existing subpart N of 

part 98 or subpart U of part 98, would 

provide a more accurate estimation 

methodology for these emissions. 

Methods for calculating GHG 

emissions from ceramic production are 

available in the 2006 IPCC 

Guidelines,154 including methods based 

on: (1) default emission factors that 

assume limestone and dolomite are the 

only carbonates contained in clay and 

that 85 percent of carbonates consumed 

are limestone and 15 percent of 

carbonates consumed are dolomite; (2) 

facility-specific data on the quantity of 

limestone versus dolomite consumed; 

and (3) a carbonate input approach that 

accounts for all carbonates (species and 

amounts) and which mirrors the 

methodology used for estimating CO2

emissions from glass production in 

subpart N of part 98. We are considering 

whether emissions could be estimated 

for the ceramics production source 

category by modifying these 

methodologies to consider facilityspecific inputs. Facilities could 

potentially also use a CEMS to monitor 

CO2 emissions from the kiln or dryer 

and use the CEMS data to report GHG 

emissions. More information about 

these potential methods can be found in 

the document, Technical Support 

Document for Ceramics: Proposed Rule 

for The Greenhouse Gas Reporting 

Program, available in the docket for this 

rulemaking (Docket Id. No EPA–HQ– 

OAR–2019–0424). 

The EPA seeks comment on whether 

it should add a source category related 

to ceramics production, and if so, seeks 

information that could be related to 

source category definitions, calculation 

methodologies, and reporting 

requirements. For example, we are 

soliciting comment on how the source 

category should be defined, and 

whether it should be included as a 

separate category or as part of an 

existing category, either subpart N 

(Glass Production) or subpart U 

(Miscellaneous Uses of Carbonate). We 

also seek comment on which IPCC 

calculation methodologies or other 

methodologies, including those listed in 

the document, Technical Support 

Document for Ceramics: Proposed Rule 

for the Greenhouse Gas Reporting 

Program, should be used, with 

consideration of what information is 

readily available to reporters. Finally, 

we are requesting input on available 

monitoring methodologies or quality 

assurance requirements that should be 

used, including what data is readily 

available for reporting that would help 

to support emissions estimates. 

C. Calcium Carbide Production 

Calcium carbide (CaC2) is used in 

production of acetylene (for cutting and 

welding) and calcium cyanamide (for 

industrial agricultural fertilizers). CaC2

is manufactured from lime and carboncontaining raw materials (usually 

petroleum coke), by heating the mixture 

to approximately 2,000 degrees Celsius 

in an EAF. Use of carbon-containing raw 

materials in the production process 

results in CO2 and CO emissions. In 

addition, any presence of hydrogencontaining volatile compounds and 

sulfur in the carbon-containing raw 

materials may cause formation of CH4

and SO2 emissions. Also, production of 

acetylene from CaC2 results in CO2

emissions. 

The EPA is considering future 

amendments to the GHGRP to add a 

source category related to CaC2

production (which may potentially also 

include acetylene production if a 

facility produces acetylene at their CaC2

production facility). The IPCC 2006 

Guidelines currently identify both 

silicon carbide production and calcium 

carbide production as potential sources 

of GHG emissions.155 Although the 

GHGRP currently accounts for 

emissions from silicon carbide 

production processes, and the GHGRP 

collects data from silicon carbide 

production under subpart BB, emissions 

from CaC2 production are not explicitly 

accounted for. Addition of a CaC2

production source category to the 

GHGRP would better align with 

intergovernmental approaches to 

estimating emissions, improve the 

completeness of the data collected 

under the GHGRP, add to the EPA’s 

understanding of the GHG data, and 

better inform future EPA policy. 

Further, such data would be available to 

improve the estimates provided in the 

U.S. GHG Inventory, by improving 

completeness and comparability of the 

estimates consistent with the 2006 IPCC 

guidelines. 

The EPA has identified a CaC2

production facility currently operating 

in the United States that is voluntarily 

reporting GHG emissions under subpart 

K (Ferroalloy Production) of part 98. 

Annual emissions from the reporting 

facility range between less than 10,000 

and 50,000 mtCO2e. We are considering 

whether adding the calcium carbide 

source category, either as a separate 

source category or combined with the 

existing silicon carbide production 

category under subpart BB of part 98, 

would provide more accurate 

applicability requirements and 

emissions estimation methodologies for 

these types of facilities. We are also 

considering, where acetylene 

production from CaC2 occurs at the 

same facility, whether we should 

account for emissions from these 

sources. 

We are considering several options for 

how emissions could be estimated for 

CaC2 production at a facility-level based 

on methods available in the 2006 IPCC 

Guidelines, including methods based 

on: (1) default emission factors applied 

to activity data on petroleum coke 

consumption or CaC2 production; (2) a 

carbon consumption methodology that 

assumes a stoichiometric conversion 

where two-thirds of the carbon 

consumed is in the CaC2 product and 

one-third is emitted as CO2 (similar to 

the estimation methods used for the 

silicon carbide production source 

category in subpart BB); and (3) a carbon 

balance method that uses measured 

quantities of carbon consumed in the 

process and carbon contained in the 

CaC2 product. Facilities could 

potentially also estimate CO2 emissions 

using CEMS. More information about 

these potential methods and the 

production of CaC2 can be found in the 

document, Technical Support 

Document for Calcium Carbide: 

Proposed Rule for the Greenhouse Gas 

Reporting Program, available in the 

docket for this rulemaking (Docket Id. 

No. EPA–HQ–OAR–2019–0424). 

The EPA seeks comment on whether 

it should add a source category related 

to CaC2 production, and if so, seeks 

information related to source category 

definitions, calculation methodologies, 

and reporting requirements. For 

example, we solicit comment on how 

the source category should be defined, 

and whether it should be included as a 

separate category or, due to similarity in 

estimation methods, as part of the 

existing silicon carbide production 

category. We also request comment on 

whether additional CaC2 production 

facilities (other than Carbide Industries 


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156 IPCC 2006. IPCC Guidelines for National 

Greenhouse Gas Inventories, Volume 3, Industrial 

Processes and Product Use. Chapter 3, Chemical 

Industry Emissions. 2006. https://www.ipccnggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_

3_Ch3_Chemical_Industry.pdf. 

157 Id. 

158 Id. 

159ChemView. Compilation of data submitted 

under TSCA in 2012 and 2016. https://

chemview.epa.gov/chemview. Accessed April 2021. 

160 In 2015, four facilities indicated that their 

glyoxal production status (i.e., as a domestic 

manufacturer or as an importer) and their quantities 

domestically manufactured and/or imported, were 

CBI. Thus, it is possible that one or more of these 

four glyoxal production facilities could be a 

domestic manufacturer. 

161 IPCC 2006. IPCC Guidelines for National 

Greenhouse Gas Inventories, Volume 3, Industrial 

Processes and Product Use. Chapter 3, Chemical 

Industry Emissions. 2006. https://www.ipccnggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_

3_Ch3_Chemical_Industry.pdf. 

162As previously mentioned, the 2006 IPCC 

Guidelines, CO2 emissions generated from C6H11NO 

production are likely to be insignificant. 

LLC in Louisville, KY) are currently 

operating in the United States. In 

addition, we seek comment on which 

tier calculation methodology as well as 

the monitoring or measurement 

methodologies should be used, 

particularly the methodology(s) for 

which facilities would have information 

readily available. Furthermore, we seek 

comment on whether any CaC2

production facility currently operating 

in the United States uses the CaC2

product to produce acetylene at the 

same facility, and whether emissions 

from acetylene production should be 

accounted for in the emission estimate 

methodology. Finally, we seek input on 

available monitoring methodologies that 

should be used, as well as input on 

what data are readily available for 

reporting that would help to support 

emissions estimates. 

D. Glyoxal, Glyoxylic Acid, and 

Caprolactam Production 

Glyoxal (C2H2O2) is used in a variety 

of applications 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; as a chemical intermediate in 

the production of pharmaceuticals, 

dyestuffs, glyoxylic acid, and other 

chemicals; and to improve moisture 

resistance in wood treatment. Glyoxal is 

also being used as a less toxic substitute 

for formaldehyde in some applications 

such as wood adhesives and embalming 

fluids. Glyoxal is commercially 

manufactured by either: (1) the gasphase catalytic oxidation of ethylene 

glycol with air in the presence of a 

silver or copper catalyst (the LaPorte 

process); or (2) the liquid-phase 

oxidation of acetaldehyde with nitric 

acid. Glyoxylic acid (C2H2O3) is used 

mainly in the synthesis of vanillin, 

allantoin, and several antibiotics like 

amoxicillin, ampicillin, and the 

fungicide azoxystrobin. Glyoxylic acid 

is exclusively produced by the 

oxidation of glyoxal with nitric acid. 

Caprolactam (C6H11NO) is a monomer 

used in carpet manufacturing. The 

addition of hydroxylamine sulphate to 

cyclohexanone produces cyclohexanone 

oxime, which can then be converted to 

caprolactam. 

The production of any of these 

organic compounds (glyoxal, glyoxylic 

acid, and caprolactam) results in N2O 

and CO2 emissions. N2O emissions are 

created from either oxidation or 

reduction steps that occur in each 

process. Our knowledge of the 

mechanisms that generate CO2

emissions from glyoxal and glyoxylic 

acid production is less understood. The 

IPCC 2006 Guidelines state that CO2

emissions generated from caprolactam 

production are unlikely to be significant 

in well-managed plants.156

The EPA is considering future 

amendments to the GHGRP to add a 

source category related to glyoxal, 

glyoxylic acid, and caprolactam 

production to improve the completeness 

of the data collected under the GHGRP, 

add to the EPA’s understanding of the 

GHG data and better inform future EPA 

policy. Emissions from these processes 

are not currently estimated in U.S. GHG 

Inventory. Therefore, once collected, 

such data would be available to and 

improve on the estimates provided in 

the U.S. GHG Inventory, by 

incorporating the recommendations of 

the 2006 IPCC guidelines, which 

currently identify glyoxal, glyoxylic 

acid, and caprolactam production as 

potential sources of GHG emissions.157

Grouping these three organic 

compounds together into one source 

category for GHGRP purposes would be 

reasonable because the 2006 IPCC 

guidelines methodology for estimating 

GHG emissions from the production of 

these compounds does the same.158

We are unsure whether there are any 

glyoxal and/or glyoxylic acid 

production facilities currently operating 

in the United States. Based on available 

2015 data reported under the Toxic 

Substances Control Act (TSCA), four 

facilities could be domestic 

manufacturers of glyoxal.159 160 Also, 

although four facilities reported 

glyoxylic acid data under the TSCA, 

each of these facilities reported no 

domestically manufactured glyoxylic 

acid. We note that more recent data for 

2016 through 2019 are expected to be 

published by the TSCA, but these data 

were not available at the time of writing 

this proposal. Nevertheless, it is 

possible that there are other glyoxal and 

glyoxylic acid production facilities 

operating in the United States, but that 

are not reporting under the TSCA 

because their total production volume is 

less than 25,000 pounds per year, or 

they are exempt from reporting because 

they are a small manufacturer based on 

their total company sales revenue. 

Currently, two caprolactam production 

facilities report GHG emissions under 

subpart C of part 98 (General Stationary 

Fuel Combustion Sources) (each facility 

reported RY2019 combustion emissions 

of approximately 600,000 to 800,000 

mtCO2e). 

Methods for calculating N2O 

emissions from glyoxal, glyoxylic acid, 

and caprolactam production are 

available in the 2006 IPCC Guidelines, 

including methods based on: (1) total 

nationwide production quantities using 

default uncontrolled emission factors; 

(2) plant-specific production quantities 

using plant-specific or default N2O 

generation and control emission factors; 

and (3) plant-specific production 

quantities and direct measurement of 

emissions to calculate plant-specific 

emission factors.161 Although the 2006 

IPCC Guidelines do not provide 

methods for calculating CO2 emissions 

from glyoxal and glyoxylic acid 

production,162 we are considering use of 

either a default emission factor 

approach for N2O and a mass balance 

approach for CO2, or development of 

site-specific factors for both N2O and 

CO2. In the first approach, N2O 

emissions would be calculated using 

production and the IPCC default factors, 

and for CO2, the mass balance 

procedures would be similar to mass 

balances required for existing subparts 

in the GHGRP such as petrochemical 

production (subpart X). Specifically, 

site-specific quantities of all carboncontaining feedstocks and products 

would be determined, and CO2

emissions would be calculated 

assuming all carbon from the feedstock 

that does not end up in product is 

emitted as CO2. We recognize that if the 

N2O is controlled using something other 

than thermal or catalytic destruction 

(that would not convert hydrocarbons to 

CO2), then this mass balance approach 

would not work for CO2. Alternatively, 

N2O and CO2 emissions could be 

calculated using site-specific production 

and site-specific emission factors that 

are developed based on flow 

measurement and periodic sampling 

and compositional analysis of the 


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streams to the control and exiting the 

control. These emission factors would 

be multiplied by the site-specific 

production quantity to calculate 

emissions. More information about 

these N2O and CO2 emission calculation 

methods and the production of glyoxal, 

glyoxylic acid, and caprolactam can be 

found in the document, Technical 

Support Document for Glyoxal, 

Glyoxylic Acid, and Caprolactum 

Production: Proposed Rule for The 

Greenhouse Gas Reporting Program, 

available in the docket for this 

rulemaking (Docket Id. No EPA–HQ– 

OAR–2019–0424). 

The EPA seeks comment on whether 

it should add a source category related 

to glyoxal, glyoxylic acid, and 

caprolactam production, and if so, seeks 

information that could be related to 

source category definitions, calculation 

methodologies, and reporting 

requirements. For example, we solicit 

comment on how the source category 

should be defined. In addition, as 

previously mentioned, although we are 

aware of at least two caprolactam 

production facilities, we are unsure 

whether there any glyoxal and/or 

glyoxylic acid production facilities 

currently operating in the U.S.; 

therefore, we seek information about 

whether these types of facilities are 

currently operating in the U.S. We 

request comment on whether facilities 

have installed abatement equipment. 

We also solicit comment on which tier 

calculation methodologies or other 

methodologies, including those outlined 

in the document Technical Support 

Document for Glyoxal, Glyoxylic Acid, 

and Caprolactum Production: Proposed 

Rule for The Greenhouse Gas Reporting 

Program, available in the docket for this 

rulemaking (Docket Id. No EPA–HQ– 

OAR–2019–0424), should be used to 

determine GHG emissions from these 

types of facilities and which 

information or inputs for these 

methodologies is readily available. 

Furthermore, as previously mentioned, 

although we are considering a mass 

balance approach to determine CO2

emissions from these types of facilities, 

our knowledge of the mechanisms that 

generate CO2 emissions from glyoxal 

and glyoxylic acid production are not 

fully understood; therefore, we request 

information on this subject. Finally, we 

seek input on available monitoring 

methodologies and quality assurance 

procedures that should be used; and 

input on what data are readily available 

for reporting that would help to support 

emissions estimates. 

E. Coke Calcining 

Calcined petroleum coke is a nearly 

pure carbon material used primarily to 

make anodes for the aluminum, steel, 

and titanium smelting industries. The 

process used to produce calcined 

petroleum coke is called coke 

calcination and is commonly performed 

in coke calciners that are rotary kilns or 

rotary furnaces equipped with an 

afterburner. Coke calcining uses ‘‘green’’ 

petroleum coke with low metals content 

(commonly called ‘‘anode grade 

petroleum coke’’) as a feed material. The 

coke is then heated to high temperatures 

in the absence of air or oxygen for the 

purpose of removing impurities or 

volatile substances in the green coke. 

Auxiliary fuel is needed to start-up the 

kiln or furnace, but once the desired 

calcining temperature is reached, 

process gas consisting of volatile 

organics and sulfur-containing 

compounds driven from the coke are 

used as the primary fuel to maintain 

calciner temperatures. Similarly, the 

coke calciner afterburner combusts 

primarily the process off-gas and 

requires little, if any, auxiliary fuel 

except during start-up. The afterburner 

is used to convert excess process gas to 

CO2 and SO2, and a waste heat boiler 

may be used to recover energy from this 

combustion process. The afterburner 

will also likely release trace amounts of 

CH4 and N2O, similarly to other 

stationary combustion devices. The 

afterburner off-gas is emitted to the 

atmosphere and is the primary source of 

GHG emissions from this process. 

Coke calcining processes may be colocated with petroleum refineries or 

may be independent facilities. 

Currently, coke calcining processes colocated at petroleum refineries must 

calculate and report emissions from 

coke calciners following the 

methodologies specified in subpart Y of 

part 98 (Petroleum Refineries). Several 

coke calciners not co-located at 

petroleum refineries report emissions 

that are calculated using the calculation 

methodologies under subpart C of part 

98 (General Stationary Fuel Combustion 

Sources). The calculation methodologies 

in subparts C and Y, for facilities not 

using CEMS, are substantially different, 

resulting in inconsistent 

characterization of emissions between 

the two populations of sources. 

Specifically, the subpart C emission 

calculations assume that the carbon 

content of the fuel burned is represented 

by the default carbon content of 

petroleum coke and that the carbon in 

the petroleum coke is fully combusted 

and converted to CO2 whereas the 

subpart Y calculation uses a mass 

balance approach to account for the fact 

that the carbon content in the final 

product is higher than the carbon 

content in the petroleum coke fed to the 

unit, thereby more accurately 

accounting for the carbon content in the 

process gas actually combusted. The 

EPA is considering future amendments 

to the GHGRP to add a coke calcining 

source category to require specific 

calculation methodologies and reporting 

requirements for coke calciners not colocated with petroleum refineries, in 

order to improve the completeness of 

the data collected under the GHGRP and 

better inform future EPA policy. 

Incorporating a new source category 

would improve the consistency of 

emission calculation methodologies for 

coke calcining processes units 

regardless of whether nor not they are 

co-located with a petroleum refinery. 

The EPA seeks comment on whether a 

separate source category for coke 

calcining facilities should be added to 

the GHGRP. 

The EPA identified 15 coke calcining 

facilities operating 29 coke calcining 

process units in the United States. Most 

coke calcining facilities are located at or 

near a petroleum refinery. Three of the 

facilities report GHG emission under 

subpart Y. The remaining facilities 

either do not report coke calcining 

emissions or report emissions under 

subpart C. Based on data reported to the 

GHGRP for RY2019, the typical coke 

calcining facility emits 150,000 mtCO2e 

per year. With 15 operating facilities in 

the U.S., it is estimated that these 

facilities emit 2.2 million mtCO2e per 

year. The EPA seeks information on the 

total number of facilities currently 

operating coke calciners in the United 

States. 

There are four possible calculation 

methodologies for determining GHG 

emissions from coke calciners, shown in 

order of most accurate to least: (1) use 

of CEMS; (2) a mass balance using the 

carbon content of the green and calcined 

coke; (3) a mass balance using a fixed 

methane content in the coke and using 

a mass reduction in the quantity of coke 

fed to the process and the quantity of 

coke leaving the process; and (4) using 

either default high heat values and CO2

emission factors or assuming the 

reduction in the mass of coke is solely 

due to the combustion of green coke fed 

to the calciner. More information about 

these methods and the coke calcining 

process can be found in the 

memorandum, Technical Support 

Document for Coke Calcining: Proposed 

Rule for The Greenhouse Gas Reporting 

Program, available in the docket for this 

rulemaking (Docket Id. No EPA–HQ– 

OAR–2019–0424). 


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163The EPA notes that aggregated totals of 

primary end uses for CO2 captured and produced 

are available on the GHGRP website at https://

www.epa.gov/ghgreporting/supply-undergroundinjection-and-geologic-sequestration-carbondioxide. 

Subpart Y allows the use of CEMS 

(methodology (1), as noted above). If 

CEMS are not used, subpart Y requires 

the use of a carbon mass balance 

approach using equation Y–13 

(methodology (2), as noted above). 

Facilities using equation Y–13 must 

measure the mass of petroleum coke in 

and out of the process and the carbon 

content of the coke in and out of the 

process. Subpart Y also requires 

estimating CH4 and N2O emissions 

based on the CO2 emissions, and the 

ratio of the CH4 or N2O emission factor 

for ‘‘petroleum products’’ in Table C–2 

of subpart C and the CO2 emission factor 

for petroleum coke in Table C–1 of 

subpart C of part 98. If a new subpart 

for coke calcining is developed, the EPA 

seeks comment on the appropriate 

calculation method(s) to require. The 

EPA is also seeking comment on 

whether coke calcining facilities are 

already collecting the necessary 

information to estimate GHG emissions 

using methodologies (2), (3), and (4), as 

described in this section. We are also 

seeking comment on appropriate 

monitoring for the four methodologies 

described in the Technical Support 

Document for Coke Calcining: Proposed 

Rule for The Greenhouse Gas Reporting 

Program, available in the docket for this 

rulemaking (Docket Id. No EPA–HQ– 

OAR–2019–0424). Finally, we are 

seeking input on appropriate missing 

data and quality assurance procedures. 

F. CO2 Utilization 

As mentioned in the previous section, 

CCUS refers to a set of technologies that 

capture CO2 from the emissions of large 

point sources or ambient air, transport 

it, compress it, and either utilize it or 

inject it in deep underground for safe 

and secure storage. CO2 utilization is a 

quickly growing area of interest among 

stakeholders and there is currently a 

lack of publicly available and nationally 

consistent GHG data regarding CO2

utilization. As technologies scale up and 

markets develop for CO2 utilization, the 

potential for GHG mitigation through 

CO2 utilization is expected to greatly 

expand. There are a broad range of CO2

utilization pathways (i.e., technological 

approaches for carbon utilization), with 

each utilization pathway having its own 

set of specific characteristics in terms of 

products manufactured, technical 

maturity, market potential, economics, 

potential to displace existing products 

or sources of CO2, and lifecycle GHG 

impact. 

The EPA is considering amendments 

to part 98 to add a source category 

related to CO2 utilization. While part 98 

has source categories related to 

Suppliers of Carbon Dioxide (subpart 

PP), Injection of Carbon Dioxide 

(subpart UU) and Geologic 

Sequestration of Carbon Dioxide 

(subpart RR), it does not have a source 

category that is solely related to CO2

utilization. The inclusion of CO2

utilization as a source category in part 

98 could fill a critical informational gap 

and inform future policy and programs 

under the CAA. 

The EPA seeks comment on whether 

we should add a source category related 

to CO2 utilization, and if so, seeks 

information related to source category 

definition; calculation, monitoring and 

QA/QC methodologies; and reporting 

requirements. 

The EPA seeks comment on how the 

source category would be defined. In 

order to define the source category, the 

EPA seeks information to contextualize 

potential reporters and understand how 

this reporting would relate to other 

source categories of the GHGRP. For 

example, the EPA seeks comment on 

different types of end products that 

utilize CO2 (currently and potentially), 

the amount of captured CO2 used per 

unit of production or manufacture 

(gallons, metric tons, etc.) for different 

processes (currently and potentially), 

including processes that do not result in 

manufacture of marketable product (e.g., 

ex-situ mineralization for storage only). 

Additionally, the EPA seeks comment 

on the total amount of captured CO2

being used in the end use per year for 

different manufacturing processes or 

utilization pathways (currently and 

potentially),163 whether there should be 

a threshold for reporting, and if so, how 

that threshold should be defined. The 

EPA seeks information on the total 

number of facilities (currently and 

potentially), and how many facilities 

would be reporting under different 

potential thresholds. The EPA requests 

comment on whether particular CO2

utilization pathways should be included 

in the source category, and if so, how 

should those pathways be defined. The 

EPA also requests comment on whether 

the source category should include 

reporting of not only CO2, but also other 

greenhouse gases. 

The EPA seeks comment on what 

calculation methodologies should be 

used for purposes of part 98 reporting. 

For example, most source categories 

reporting under part 98 focus on 

reporting of direct emissions. Taking a 

similar approach for CO2 utilization 

would exclude emissions associated 

with the end use of the CO2 in the 

product. A full accounting of all GHGs 

from cradle to grave, including the 

potential to displace an existing product 

or other existing source of CO2, would 

be needed to understand the product’s 

life cycle and total GHGs emitted. To 

that end, the EPA seeks input regarding 

whether a GHG LCA should be required, 

and if so, what information, protocols, 

guidance, and/or models would be 

required to conduct the LCA, who 

should validate it, what information 

would need to be reported to support 

the LCA validation, and to what extent 

LCA information is already reported 

through other GHGRP subparts. 

In addition to calculation 

methodologies, the EPA seeks comment 

on what monitoring requirements 

should be in place and what 

methodologies are recommended for 

monitoring and QA/QC. LCA is also 

relevant with regard to monitoring, as 

CO2 can be stored and emitted at 

various stages of the product’s lifecycle, 

and the length of CO2 storage varies 

between CO2 utilization pathways and 

end products. The EPA also seeks 

comment on how permanence of the 

CO2 storage should be defined and 

addressed if LCA were not required. 

Similarly, the EPA seeks comment on 

information that could be used for, and 

the feasibility of developing, 

sequestration lifetimes for various 

products that result from different 

utilization pathways. For both 

calculation and monitoring of CO2

utilization under part 98 reporting, the 

EPA seeks comment on QA/QC 

practices to ensure consistent and 

accurate estimates. 

Finally, the EPA requests comment on 

the reporting requirements related to 

CO2 utilization. CO2 utilization 

technologies can vary widely (e.g., 

biological, chemical, or physical 

processes), and many technologies are 

still emerging. The EPA seeks input on 

how to manage reporting of these highly 

variable and emerging technologies. For 

example, we are seeking comment on 

whether different technology categories 

should have different calculation, 

monitoring, and reporting requirements. 

Additionally, the EPA requests 

comment regarding specific data 

elements to be reported. This includes 

the amount of CO2 utilized, types of 

greenhouse gases to be reported (i.e., 

reporting of not only CO2, but also other 

greenhouse gases), and end uses of the 

CO2. It also includes emissions of 

greenhouse gases throughout the 

lifecycle of a product, and more 

specifically emissions of greenhouse 

gases during the utilization process, the 

ultimate fate of the CO2 used, and the 


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164U.S. Environmental Protection Agency & 

International Aluminium Institute. (2008). Protocol 

for Measurement of Tetrafluoromethane (CF4) and 

Hexafluoroethane (C2F6) Emissions from Primary 

Aluminum Production. Available in the docket for 

this rulemaking (Docket Id. No. EPA–HQ–OAR– 

2019–0424). 

165Available at https://internationalaluminium.org/resource/good-practice-guidancemeasuring-perfluorocarbons/ and in the docket for 

this rulemaking (Docket Id. No. EPA–HQ–OAR– 

2019–0424). 

166Available at https://internationalaluminium.org/resource/good-practice-guidancemeasuring-perfluorocarbons/ and in the docket for 

this rulemaking (Docket Id. No. EPA–HQ–OAR– 

2019–0424). 

sequestration lifetime of the utilized 

CO2. EPA also seeks comment on 

whether the source of CO2 used in the 

utilization process should be reported, 

and if so, what information on the 

source should be reported (e.g., 

captured versus extracted, sector or type 

of facility from which the CO2 was 

captured and sourced, and/or facilityspecific information for where CO2 was 

captured and sourced). 

G. Aluminum Production 

The EPA is considering proposing to 

amend subpart F of part 98 (Aluminum 

Production) to add reporting of low 

voltage emissions and cell-start-up 

emissions. The EPA is also considering 

updating cell technology categories to 

be consistent with the 2019 Refinement. 

The EPA is also considering updating or 

replacing the 2008 Protocol 164 (used for 

development of the current emissions 

measurement methodology) based on 

the 2020 International Aluminium 

Institute (IAI) ‘‘Good Practice Guidance: 

Measuring Perfluorocarbons’’ 165

(hereafter referred to as ‘‘2020 IAI Good 

Practice Guidance’’) and the 2008 U.S. 

EPA/IAI ‘‘Protocol for Measurement of 

Tetrafluoromethane (CF4) and 

Hexafluoroethane (C2F6) Emissions from 

Primary Aluminum Production’’ 166

developed by the IAI. Low voltage 

anode effects (LVAEs), where the cell 

voltage does exceed the voltage 

threshold, have been identified as a 

source of CF4 emissions and can be a 

significant portion of the emissions in 

modern high-amperage cells with many 

large anodes. Emissions from LVAEs 

would be better characterized by 

measuring emission factors specifically 

for low voltage emissions. Emissions of 

CF4 from LVAEs have not previously 

been included due to a lack of data and 

methodology for their estimation. 

However, the 2019 Refinement provides 

several methods for estimating LVAE 

emissions. The 2019 Refinement also 

provides methods for potentially more 

accurately characterizing cell start-up 

emissions and high voltage anode effect 

emissions (HVAEs) through the addition 

of new non-linear Tier 3 methods. The 

2020 IAI Good Practice Guidance 

provides additional guidance on 

measurement frequency, calculation of 

emission factors using new Tier 3 

calculation methods available in the 

2019 Refinement and updating methods 

to account for both low voltage and high 

voltage emissions of PFCs. In addition 

to improving the accuracy of emissions 

reported the GHGRP and adding to the 

EPA’s understanding of facility-level 

emissions from this source category, the 

collection of low voltage and start-up 

emissions data would also improve 

emissions estimates for the U.S. GHG 

Inventory and better inform future EPA 

policy. Currently the U.S. GHG 

Inventory uses a Tier 1 emission factor 

to estimate LVAE emissions, based on 

production technology and high voltage 

emission estimates, which may 

overestimate low voltage emissions. 

However, the LVAE data is still 

somewhat limited. Additional studies 

would help to assess how frequently 

measurements must be made to 

maintain an accurate accounting of 

smelter emissions, including low 

voltage emissions. Studies are also 

needed to assess the relative advantages 

in robustness and accuracy of the nonlinear method for calculating HVAE PFC 

emissions. The EPA requests comment 

on the extent to which low voltage 

emissions have been characterized and 

if data is available to develop guidance 

on low voltage emission measurements 

needed to develop robust LVAE 

emission factors. The EPA also requests 

comment 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 

is also requesting comment on the 

methods and protocols in the 2020 IAI 

Good Practice Guidance. 

V. Schedule for the Proposed 

Amendments 

The EPA is planning to consider the 

comments on these proposed changes, 

and, if any of the proposed amendments 

are finalized, to respond to the 

comments and publish any amendments 

before the end of 2022. We are 

proposing that these amendments 

would become effective on January 1, 

2023 and that reporters would 

implement the changes beginning with 

reports prepared for RY2023 and 

submitted April 1, 2024. 

We have determined that it would be 

feasible for existing reporters to 

implement the proposed changes for 

RY2023 because the revisions primarily 

include improvements to the rule that 

are consistent with the current data 

collection and calculation 

methodologies. Some of the proposed 

amendments would clarify and improve 

the existing rule in order to enhance the 

quality and accuracy of the data 

collected. These revisions primarily 

provide additional clarifications or 

flexibility regarding the existing 

regulatory requirements, do not add 

new monitoring or sampling 

requirements, and do not substantially 

affect the information that must be 

collected (i.e., require new data 

collection). In the limited cases where 

we are proposing to require the 

collection of additional data, such as 

from subpart W (Petroleum and Natural 

Gas Systems) facilities, we are 

proposing to allow reporters to use 

BAMM for the first annual report 

submitted for RY2023 (as discussed in 

section III.J of this preamble), which 

would provide additional time for 

facilities to adapt to new monitoring 

requirements and, for example, install 

the appropriate equipment. Where 

calculation equations are proposed to be 

modified, the changes clarify equation 

terms or simplify the calculations, and 

do not require any additional data 

monitoring. In these cases, we anticipate 

that facilities would have any additional 

inputs for calculations available in 

company records or could easily 

calculate the required input from 

existing process knowledge and 

engineering estimates, or from available 

company records. Therefore, these types 

of changes are not anticipated to add 

significant burden for reporters. 

Although we are proposing one change 

to require additional reporting under 

subpart C (for separate reporting of 

biogenic emissions from the combustion 

of tires), because we are simultaneously 

proposing removal of the ‘‘less than 10 

percent’’ restriction on using the default 

biogenic CO2 factor to estimate biogenic 

emissions in 40 CFR 98.33(e)(3)(iv), the 

new reporting would not require any 

additional monitoring or data collection. 

As such, all reporters who combust tires 

would be able to use the default 

biogenic CO2 factor, and would not need 

to conduct quarterly flue-gas testing, to 

establish the biogenic fraction of 

emissions. 

In several instances we are proposing 

to require reporting of additional data 

elements to improve verification of 

annual reports, provide a more complete 

picture of GHG emissions or supply, or 

develop factors that may inform the U.S. 

GHG Inventory. As provided in section 

III of this preamble, in these instances 

we anticipate that the data is already 

available in company records (e.g., 

production or material use data, or data 

on product or equipment type). In most 


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cases the data we are requesting can be 

calculated using data that is already 

required to be entered into the EPA’s 

reporting system, is already maintained 

in keeping with existing facility data 

permits (e.g., hours of operation an 

abatement device was not in use), or 

may be estimated using emission factors 

or engineering judgment. For example, 

where we are proposing to add reporting 

of unit specific data for subpart C 

(General Stationary Fuel Combustion 

Sources) reporters using the aggregation 

of units or common pipe configurations, 

facilities already collect data on the 

maximum rated heat input capacity of 

individual units in each aggregation of 

units or common pipe configuration 

(greater than or equal to 10 mmBtu/hr) 

to determine the reported cumulative 

maximum rated heat input capacity, and 

would be able to determine the other 

data elements requested (i.e., unit type 

and estimate of the fraction of annual 

heat input) from their existing company 

records. 

Additionally, although we are 

proposing the addition of calculation 

and reporting requirements under new 

subpart VV (Geologic Sequestration of 

Carbon Dioxide with Enhanced Oil 

Recovery Using ISO 27916), we do not 

anticipate that the new subpart would 

expand the existing coverage of facilities 

subject to the GHGRP, but would only 

apply to those reporters that currently 

report under subpart UU (Injection of 

Carbon Dioxide) and that choose to 

report amounts of CO2 stored under the 

proposed subpart VV. It is anticipated 

that these facilities already follow the 

calculation requirements and data 

gathering prescribed under CSA/ANSI 

ISO 27916:2019 (e.g., as discussed in 

section III.W of this preamble, to 

quantify storage for the IRC section 45Q 

tax credit); would not perform any 

additional calculation, monitoring, or 

quality assurance procedures under the 

proposed requirements; and that the 

information submitted to the GHGRP 

would be obtained and provided from 

readily available data. These facilities 

will also retain the option to continue 

to report under existing subpart UU 

with no changes. Therefore, we have 

determined that it would be feasible for 

facilities who opt to report under 

proposed subpart VV to implement the 

proposed changes for RY2023. 

Other proposed changes streamline 

and improve implementation by 

simplifying or clarifying calculation, 

monitoring, and recordkeeping, or 

reporting. These types of changes are 

intended to simplify or provide 

flexibility in the requirements that 

reporters must meet and do not require 

additional data collection. For these 

reasons, we believe that a proposed 

effective date of January 1, 2023 is 

reasonable. Reporters are not required to 

submit RY2023 reports until April 1, 

2024, which is over a year after we 

expect a final rule based on this 

proposal to be finalized, if finalized, 

thus providing an opportunity for 

reporters to adjust to any finalized 

amendments. The proposed effective 

date would also allow ample time for 

the EPA to implement the changes into 

e-GGRT. 

We are proposing one change that 

would impact the date of submittal of a 

non-annual report. For subpart I, we are 

proposing to revise the frequency of 

submittal of the technology assessment 

reports required under 40 CFR 98.96(y). 

The proposed change would revise the 

frequency of submittal from three years 

to five years. Under the current rule, 

semiconductor manufacturing facilities 

are required to submit their next 

technology assessment report by March 

31, 2023 (concurrent with their RY2022 

annual report). The proposed change 

would affect the due date of the 

following technology assessment report, 

moving the due date from March 31, 

2023 to March 31, 2025. Because the 

proposed change would decrease the 

frequency of submissions and extend 

the timeframe for reporters to collect 

and compile data for the next submittal, 

we have determined that the proposed 

changes would be feasible to implement 

by this date. 

We are likewise proposing that the 

proposed CBI determinations discussed 

in section VI of this preamble would 

become effective on January 1, 2023. 

The majority of the determinations are 

for new or revised data elements that 

would be included in annual GHG 

reports prepared for RY2023 and 

submitted April 1, 2024. However, there 

are some circumstances, discussed in 

detail in section VI of this preamble, 

where the proposed determinations 

cover data included in annual GHG 

reports submitted for prior years. In 

either case, the proposed determinations 

for the data that the EPA has already 

received for these prior years or receives 

going forward for any reporting year 

would become effective on January 1, 

2023. 

VI. Proposed Confidentiality 

Determinations for Certain Data 

Elements 

A. Overview and Background 

Part 98 requires reporting of 

numerous data elements to characterize, 

quantify, and verify GHG emissions and 

related information. Following proposal 

of part 98 (74 FR 16448, April 10, 2009), 

the EPA received comments addressing 

the issue of whether certain data could 

be entitled to confidential treatment. In 

response to these comments, the EPA 

stated in the preamble to the 2009 Final 

Rule (74 FR 56387, October 30, 2009), 

that through a notice and comment 

process, we would establish those data 

elements that are entitled to confidential 

treatment. This proposal is one of a 

series of rulemakings dealing with 

confidentiality determinations for data 

reported under part 98. For more 

information on previous confidentiality 

determinations for part 98 data 

elements, see the following documents: 

• 75 FR 39094, July 7, 2010. Describes 

the data categories and category-based 

determinations the EPA developed for 

the part 98 data elements. 

• 76 FR 30782, May 26, 2011; 

hereafter referred to as the ‘‘2011 Final 

CBI Rule.’’ Assigned data elements to 

data categories and published the final 

CBI determinations for the data 

elements in 34 part 98 subparts, except 

for those data elements that were 

assigned to the ‘‘Inputs to Emission 

Equations’’ data category. 

• 77 FR 48072, August 13, 2012. 

Finalized confidentiality determinations 

for data elements reported under nine 

subparts I, W, DD, QQ, RR, SS, UU; 

except for those data elements that are 

inputs to emission equations. Also 

finalized confidentiality determinations 

for new data elements added to subparts 

II and TT in the November 29, 2011 

Technical Corrections document (76 FR 

73886). 

• 78 FR 68162; November 13, 2013. 

Finalized confidentiality determinations 

for new data elements added to subpart 

I. 

• 78 FR 69337, November 29, 2013. 

Finalized determinations for new and 

revised data elements in 15 subparts, 

except for those data elements assigned 

to the ‘‘Inputs to Emission Equations’’ 

data category. 

• 79 FR 63750, October 24, 2014. 

Revised recordkeeping and reporting 

requirements for ‘‘inputs to emission 

equations’’ for 23 subparts and finalized 

confidentiality determinations for new 

data elements in 11 subparts. 

• 79 FR 70352, November 25, 2014. 

Finalized confidentiality determinations 

for new and substantially revised data 

elements in subpart W. 

• 79 FR 73750, December 11, 2014. 

Finalized confidentiality determinations 

for certain reporting requirements in 

subpart L. 

• 80 FR 64262, October 22, 2015. 

Finalized confidentiality determinations 

for new data elements in subpart W. 

• 81 FR 86490, November 30, 2016. 

Finalized confidentiality determinations 


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for new or substantially revised data 

elements in subpart W. 

• 81 FR 89188, December 9, 2016. 

Finalized confidentiality determinations 

for new or substantially revised data 

elements in 18 subparts and for certain 

existing data elements in 4 subparts. 

In this document, we are proposing 

confidentiality determinations or 

‘‘emission data’’ designations for: 

• New or substantially revised 

reporting requirements (i.e., the 

proposed change requires additional or 

different data to be reported); 

• Existing reporting requirements for 

which the EPA did not previously 

finalize a confidentiality determination 

or ‘‘emission data’’ designation; and 

• Existing reporting requirements for 

which the EPA is proposing to amend 

existing confidentiality determinations. 

This includes cases where the EPA is 

proposing to amend confidentiality 

determinations to align with 

determinations established in 40 CFR 

part 84 under the American Innovation 

and Manufacturing Act of 2020 (AIM 

Act). 

We are also aware that a few 

confidentiality determinations finalized 

in a previous rulemaking were not clear, 

and we are now clarifying the previous 

determinations. Further, we propose to 

designate certain new or substantially 

revised data elements as ‘‘inputs to 

emission equations’’ falling within the 

definition of ‘‘emission data’’ (see 

section VI.C of this preamble for a 

discussion of ‘‘inputs to emission 

equations’’), and we are proposing to 

require reporting of those data elements. 

Table 5 of this preamble provides the 

number of affected data elements and 

the affected subparts for each of these 

proposed actions. 

Table 5 of this preamble also 

describes the effective date of these 

proposed actions. The majority of the 

determinations would apply at the same 

time as the proposed schedule described 

in section V of this preamble. In the 

cases where the EPA is proposing a 

determination for existing data elements 

where one was not previously made, or 

where the EPA is clarifying an existing 

determination, the proposed 

determination would be effective on 

January 1, 2023 for RY2023 as well as 

all prior years that the data was 

collected. For the data elements where 

we are proposing to amend previous 

determinations to align with 

rulemakings establishing 40 CFR part 84 

under the AIM Act, the proposed 

confidentiality determinations would 

apply only prospectively, starting with 

RY2022 for the reasons described in 

section VI.D of this preamble. 

TABLE 5—SUMMARY OF PROPOSED ACTIONS RELATED TO DATA CONFIDENTIALITY

Proposed actions related to data 

confidentiality 

Number of 

data 

elements a

Subparts Effective 

year 

New or substantially revised reporting requirements for which the EPA is proposing a confidentiality determination 

or ‘‘emission data’’ designation.

283 C, G, H, I, N, P, Q, S, W, X, Y, BB, DD, 

GG, HH, OO, PP, SS, VV.

RY2023. 

Existing reporting requirements for which 

the EPA is proposing a confidentiality 

determination or ‘‘emission data’’ designation because the EPA did not previously make a confidentiality determination or ‘‘emission data’’ designation.

33 A, I, K, W, HH ......................................... RY2023, and all prior years the data 

was collected. 

Existing reporting requirements for which 

the EPA is proposing to amend an existing confidentiality determination.

33 A, RR, UU ............................................... RY2023. 

Existing reporting requirements for which 

the EPA is clarifying the current confidentiality determination.

12 A, L, MM, NN .......................................... RY2023, and all prior years the data 

was collected. 

New or substantially revised reporting requirements that the EPA is proposing 

be designated as ‘‘inputs to emission 

equations’’ and for which the EPA is 

proposing reporting determinations.

125 C, I, W, DD, SS ....................................... RY2023. 

Existing reporting requirements for which 

the EPA is proposing to amend an existing confidentiality determination to 

align with determinations under the 

AIM Act.

9 OO ........................................................... RY2022. 

a These data elements are listed in the memoranda: (1) Proposed Confidentiality Determinations and Emission Data Designations for Data Elements in Proposed Revisions to the Greenhouse Gas Reporting Rule, (2) 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 (3) Proposed Determinations 

that would Align the Greenhouse Gas Reporting Program with the Determinations Made under the AIM Act Regulations, available in the docket 

for this rulemaking (Docket Id. No. EPA–HQ–OAR–2019–0424). 

Finally, we are confirming that, 

except for the cases discussed in detail 

in this proposal, part 98 data elements 

previously determined to be entitled to 

confidential treatment through 

rulemaking will continue to be treated 

as such under the standard for 

confidentiality set forth in Food 

Marketing Institute v. Argus Leader 

Media, 139 S. Ct. 2356 (2019). 


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167See section I.C of the preamble for the July 7, 

2010 CBI proposal (75 FR 39094, July 7, 2010) for 

further discussion of CAA section 114 

requirements. The term ‘‘emission data’’ is defined 

at 40 CFR 2.301(a)(2)(i). 

168Available in the docket for this rulemaking 

(Docket Id. No. EPA–HQ–OAR–2019–0424). 

169See section I.C of the July 7, 2010 proposal (75 

FR 39100) for a discussion of the definition of 

‘‘emission data.’’ As discussed therein, the relevant 

paragraphs (to the GHGRP) of the CAA definition 

of ‘‘emission data’’ include 40 CFR 2.301(a)(2)(i)(A) 

and (C), as follows: (A) ‘‘Information necessary to 

determine the identity, amount, frequency, 

concentration, or other characteristics (to the extent 

related to air quality) of any emission which has 

been emitted by the source (or of any pollutant 

resulting from any emission by the source), or any 

combination of the foregoing;’’ and (C) ‘‘A general 

description of the location and/or nature of the 

source to the extent necessary to identify the source 

and to distinguish it from other sources (including, 

to the extent necessary for such purposes, a 

description of the device, installation, or operation 

constituting the source).’’ 

B. Proposed Confidentiality 

Determinations and Emissions Data 

Designations 

1. Proposed Approach 

The EPA’s past approach for 

evaluating reporting requirements for 

confidentiality was established in the 

2011 Final CBI Rule (76 FR 30782, May 

26, 2011). This approach was based on 

the requirements of 40 CFR part 2, 

which included an assessment of 

whether disclosure of the data would 

cause a likelihood of substantial 

competitive harm. As set forth in the 

2011 Final CBI Rule, the EPA 

categorized all reporting requirements 

into 22 data categories and reviewed 

them for confidentiality as follows: 

• 12 data categories were established 

and designated as either ‘‘CBI’’ or ‘‘not 

CBI’’ (hereafter referred to as 

‘‘categorical confidentiality 

determinations’’), and all data elements 

assigned to one of these 12 data 

categories were also assigned the 

confidentiality determination of ‘‘CBI’’ 

or ‘‘not CBI’’ for that category; 

• 5 data categories were established 

that were not assigned any categorical 

confidentiality determinations; instead, 

for each data element in these 

categories, the EPA made individual 

determinations through rulemaking for 

each data element; 

• 4 data categories were established 

and designated as ‘‘emission data’’ (as 

defined in 40 CFR 2.301(a)(2)(i)) and all 

data elements assigned to these four 

data categories were assigned a 

categorical designation of ‘‘emission 

data,’’ which under CAA section 114 are 

not entitled to confidential treatment;167

therefore, no data assigned to these four 

categories were further evaluated for 

confidentiality; and 

• 1 data category, ‘‘Inputs to Emission 

Equations,’’ was proposed on July 7, 

2010 (75 FR 39094) to be ‘‘emissions 

data.’’ Evaluation of data elements 

assigned to this data category was first 

conducted in the October 24, 2014 final 

rule (79 FR 63750). Refer to section VI.C 

of this preamble for further discussion 

of the EPA’s evaluation and treatment of 

data assigned to the ‘‘Inputs to Emission 

Equations’’ data category. 

Since the 2011 Final CBI Rule, we 

have followed the approach outlined 

above in all rulemakings for evaluating 

reporting requirements for 

confidentiality. However, in this 

document we are proposing to revise 

our approach to assessing data for 

confidentiality in response to Food 

Marketing Institute v. Argus Leader 

Media, 139 S. Ct. 2356 (2019) (hereafter 

referred to as Argus Leader).168 In Argus 

Leader, the U.S. Supreme Court issued 

an opinion addressing the meaning of 

the word ‘‘confidential’’ in Exemption 4 

of the Freedom of Information Act, 5 

U.S.C. Section 552(b)(4)(2012 and Supp. 

V. 2017) stating that ‘‘confidential’’ 

must be given its ‘‘ordinary’’ meaning, 

which is information that is ‘‘private’’ or 

‘‘secret.’’ As a result, starting with the 

date of the Argus Leader ruling, the EPA 

no longer assesses data elements using 

the rationale of whether disclosure will 

cause a likelihood of substantial 

competitive harm when making 

confidentiality determinations. Instead, 

the EPA assesses whether the 

information is customarily and actually 

treated as private by the reporter and 

whether the EPA has given an assurance 

at the time the information was 

submitted that the information will be 

kept confidential or not confidential. 

We are proposing that the Argus 

Leader decision does not impact 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.’’ For a discussion of the 

EPA’s rationale for why the Argus 

Leader decision does not impact our 

previous approach for handling ‘‘inputs 

to emission equations,’’ refer to section 

VI.C of this preamble. The Argus Leader 

decision does not apply to data 

elements designated as ‘‘emission data,’’ 

because section 114(c) of the CAA 

precludes ‘‘emission data’’ from being 

considered confidential and requires 

that such data be available to the public. 

Therefore, the Argus Leader decision 

does not impact our previous approach 

for designating new and revised 

reporting requirements as ‘‘emission 

data.’’ We propose 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 to meet the CAA 

definition of ‘‘emission data’’ in 40 CFR 

2.301(a)(2)(i) 169 (hereafter referred to as 

‘‘emission data categories’’). As 

discussed in section II.B of the July 7, 

2010 proposal (75 FR 39100), the four 

emission data categories include the 

following categories of data reported by 

direct emitters (i.e., ‘‘emission data’’ 

does not apply to suppliers reporting 

under the GHGRP as discussed in 

section II.C.2 of the preamble for the 

2011 Final CBI Rule (76 FR 30782, May 

26, 2011)): 

• Category 1: Facility and Unit 

Identifier Information; 

• Category 2: Emissions; 

• Category 3: Calculation 

Methodology and Methodological Tier; 

and 

• Category 4: Data Elements Reported 

for Periods of Missing Data that are Not 

Inputs to Emission Equations. 

Refer to section II.B of the July 7, 2010 

proposal for descriptions of each of 

these data categories and the EPA’s 

rationale for designating each data 

category as ‘‘emission data.’’ Note that 

the proposed ‘‘emission data’’ 

designations discussed in section VI.B.2 

of this preamble involve assignment to 

only the first three emission data 

categories in the bulleted list above (i.e., 

we are not proposing that any reported 

elements be assigned to the ‘‘Data 

Elements Reported for Periods of 

Missing Data that are Not Inputs to 

Emission Equations’’ data category). 

For reporting elements that the EPA 

does not designate as ‘‘emission data’’ or 

‘‘inputs to emission equations,’’ the EPA 

is proposing a revised approach for 

assessing data confidentiality. We 

propose to assess each individual 

reporting element according to the 

Argus Leader criteria (i.e., whether the 

information is customarily and actually 

treated as private by the reporter); 

therefore, we are not proposing to assign 

the data elements to any data category 

established by the 2011 Final CBI Rule. 

Refer to section VI.B.2 of this preamble 

for further discussion of the EPA’s 

evaluation of data elements according to 

the Argus Leader criteria and proposed 

confidentiality determinations. 

2. Proposed Confidentiality 

Determinations and ‘‘Emission Data’’ 

Designations 

In this section, we discuss the 

proposed confidentiality determinations 


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and ‘‘emission data’’ designations for: 

(1) 283 new or substantially revised data 

elements, (2) 33 existing data elements 

(i.e., not proposed to be substantially 

revised) for which we have not 

previously finalized a confidentiality 

determination or ‘‘emission data’’ 

designation, and (3) 33 existing data 

elements for which we are amending an 

existing confidentiality determination. 

We are also clarifying 12 previous 

confidentiality determinations, as 

discussed in section VI.B.2.d of this 

preamble. 

Further, we are confirming that, 

except for the specific situations 

discussed in sections VI.B.2.c and VI.D 

of this preamble, the data elements 

previously determined to be entitled to 

confidential treatment in the following 

rulemakings will continue to be treated 

as such under the new confidentiality 

standard set forth in Argus Leader: 

• 2011 Final CBI Rule; 

• 77 FR 48072, August 13, 2012; 

• 78 FR 68162; November 13, 2013; 

• 78 FR 69337, November 29, 2013; 

• 79 FR 63750, October 24, 2014; 

• 79 FR 70352, November 25, 2014; 

• 79 FR 73750, December 11, 2014; 

• 80 FR 64262, October 22, 2015; 

• 81 FR 86490, November 30, 2016; 

and 

• 81 FR 89188, December 9, 2016. 

a. Proposed Confidentiality 

Determinations and ‘‘Emission Data’’ 

Designations for New or Substantially 

Revised Data Reporting Elements 

For the 283 new and substantially 

revised data elements, the EPA is 

proposing ‘‘emission data’’ designations 

for 90 data elements and confidentiality 

determinations for 193 data elements. 

The EPA is proposing to designate 90 

new or substantially revised data 

elements as ‘‘emission data’’ by 

assigning the data elements to three 

emission data categories (established in 

the 2011 Final CBI Rule as discussed in 

section VI.B.1 of this preamble), as 

follows: 

• 44 data elements that are proposed 

to be reported under subparts G, P, S, 

W, and VV are proposed to be assigned 

to the ‘‘Emissions’’ emission data 

category; 

• 25 data elements that are proposed 

to be reported under subparts C, Q, and 

W are proposed to be assigned to the 

‘‘Facility and Unit Identifier 

Information’’ emission data category; 

and 

• 21 data elements that are proposed 

to be reported under subparts I, W, and 

SS are proposed to be assigned to the 

‘‘Calculation Methodology and 

Methodological Tier’’ emission data 

category. 

Refer to Table 1 in the memorandum, 

Proposed Confidentiality 

Determinations and Emission Data 

Designations for Data Elements in 

Proposed Revisions to the Greenhouse 

Gas Reporting Rule, available in the 

docket for this rulemaking (Docket Id. 

No. EPA–HQ–OAR–2019–0424), for a 

list of these 88 specific data elements 

proposed to be designated as ‘‘emission 

data,’’ the proposed emission data 

category assignments for each data 

element, and the EPA’s rationales for 

the proposed emission data category 

assignments. 

The remaining 193 new and 

substantially revised data elements not 

proposed to be designated as ‘‘emission 

data,’’ or ‘‘inputs to emission 

equations,’’ are proposed to be reported 

under subparts H, N, Q, S, W, X, Y, BB, 

DD, GG, HH, OO, PP, SS, and VV. This 

proposal assesses each individual 

reporting element according to the 

Argus Leader criteria as discussed in 

section VI.B.1 of this preamble. Refer to 

Table 2 in the memorandum, Proposed 

Confidentiality Determinations and 

Emission Data Designations for Data 

Elements in Proposed Revisions to the 

Greenhouse Gas Reporting Rule, to see 

a list of these 193 specific data elements 

with this status receiving a 

determination, the proposed 

confidentiality determination for each 

data element, and the EPA’s rationales 

for the proposed confidentiality 

determinations. 

b. Proposed Confidentiality 

Determinations and ‘‘Emission Data’’ 

Designations for Existing Part 98 Data 

Reporting Elements for Which No 

Determination Has Been Previously 

Established 

We are also proposing confidentiality 

determinations and ‘‘emission data’’ 

designations for 33 data elements 

currently in subparts A, I, K, W, and HH 

for which no confidentiality 

determination or ‘‘emission data’’ 

designation has been previously 

finalized under part 98. We reviewed 

previous rulemakings and found the 

following instances where a 

confidentiality determination or 

‘‘emission data’’ designation had not 

been made: 

• For subparts A, K, and HH, three 

data elements were added in the 2009 

Final Rule following public comment. 

The EPA did not make confidentiality 

determinations in that rulemaking and 

has not finalized determinations for 

these data elements in subsequent 

rulemakings. 

• Also for subpart A, one data 

element was added in the August 13, 

2012 rulemaking (77 FR 48072) 

following public comment. The EPA did 

not make a confidentiality 

determination in that rulemaking and 

has not finalized a determination for the 

data element in a subsequent 

rulemaking. 

• For subpart I, one data element was 

added in the final rulemaking published 

on August 13, 2012 (77 FR 48072), and 

one data element was revised in the 

final rulemaking published on 

November 13, 2013 (78 FR 68162). For 

the data element added on August 13, 

2012, the EPA had not proposed a 

confidentiality determination and, 

therefore, did not finalize a 

determination in the final rule. For the 

data element revised on November 13, 

2013, the EPA retained a previous 

decision for the previous version of the 

data element not to assign a 

confidentiality determination to the data 

element (see the final rulemaking on 

August 13, 2012, 77 FR 48072). Since 

the EPA did not evaluate either data 

element for confidentiality in those two 

rulemakings or in subsequent 

rulemakings, the EPA has not 

previously finalized a confidentiality 

determination for the data element. 

• Also for subpart A, one data 

element was added in the final 

rulemaking published on December 11, 

2014 (79 FR 73750) following public 

comment. The EPA had not proposed a 

confidentiality determination or 

‘‘emission data’’ designation for the data 

element and therefore did not finalize 

confidentiality determinations in the 

final rule. 

• For Subpart W, 21 data elements 

were added or substantially revised in 

the final rulemaking published on 

November 25, 2014 (79 FR 70352) 

following public comment. 

Additionally, 5 data elements were 

added in the final rulemaking published 

on October 22, 2015 (80 FR 64242) 

following public comment. The EPA 

had not proposed a confidentiality 

determination or ‘‘emission data’’ 

designation for these new or revised 

data elements, and therefore did not 

finalize confidentiality determinations 

in the final rules. 

Of these 33 data elements, we propose 

to designate 26 data elements as 

‘‘emission data’’ and therefore they 

would not be entitled to confidential 

treatment by assigning the data elements 

to three emission data categories 

(established in the 2011 Final CBI Rule 

as discussed in section VI.B.1 of this 

preamble), as follows: 

• 11 data elements in subparts A and 

W are proposed to be assigned to the 

‘‘Emissions’’ emission data category; 

• 14 data elements in subparts A and 

W are proposed to be assigned to the 


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170See section II.C.2 of the preamble for the 2011 

Final CBI Rule (76 FR 30782, May 26, 2011) for 

further discussion of the EPA’s determination that 

the supplier data elements do not meet the 

definition of emission data. 

‘‘Facility and Unit Identifier 

Information’’ emission data category; 

and 

• 1 data element in subpart I is 

proposed to be assigned to the 

‘‘Calculation Methodology and 

Methodological Tier’’ emission data 

category. 

Refer to Table 3 in the memorandum, 

Proposed Confidentiality 

Determinations and Emission Data 

Designations for Data Elements in 

Proposed Revisions to the Greenhouse 

Gas Reporting Rule, available in the 

docket for this rulemaking (Docket Id. 

No. EPA–HQ–OAR–2019–0424), for a 

list of these 26 specific data elements 

proposed to be designated as ‘‘emission 

data’’, the proposed emission data 

category assignment for each data 

element, and the EPA’s rationale for the 

proposed emission data category 

assignments. 

For the remaining 7 existing reported 

data elements in subparts A, I, K, W, 

and HH for which no confidentiality 

determination or ‘‘emission data’’ 

designation has been previously 

finalized under part 98, we propose to 

assess each individual data element 

according to the Argus Leader criteria as 

discussed in section VI.B.1 of this 

preamble. Refer to Table 4 in the 

memorandum, Proposed Confidentiality 

Determinations and Emission Data 

Designations for Data Elements in 

Proposed Revisions to the Greenhouse 

Gas Reporting Rule (available in the 

docket for this rulemaking (Docket Id. 

No. EPA–HQ–OAR–2019–0424), for a 

list of each of these seven specific data 

elements with this status receiving a 

determination, the proposed 

confidentiality determination for each 

data element, and the EPA’s rationales 

for the proposed confidentiality 

determinations. 

c. Proposed Confidentiality 

Determinations for Existing Part 98 Data 

Reporting Elements for Which a 

Previous Determination Is Proposed To 

Be Amended 

We are proposing to amend the 

confidentiality determinations 

previously finalized under part 98 for 

five existing data elements in subpart A, 

16 data elements in subpart RR, and 12 

data elements in subpart UU. In 

amending the confidentiality 

determinations, we propose to evaluate 

each individual data element according 

to the Argus Leader criteria as discussed 

in section VI.B.1 of this preamble. Three 

of these data elements from subpart A 

(40 CFR 98.3(c)(5)(ii)(A) through (C)) 

were added to subpart A in the 

December 9, 2016 rulemaking (81 FR 

89188). The EPA finalized 

confidentiality determinations for these 

three data elements in that rule. We are 

now proposing to amend those finalized 

confidentiality determinations from 

‘‘emissions data’’ to ‘‘not CBI’’ for the 

data reported by suppliers under 

subpart OO. We are amending the 

previous determinations, because no 

data reported by suppliers meet the 

definition of ‘‘emission data’’ for the 

purposes of the GHGRP.170 Two more 

data elements from subpart A (40 CFR 

98.3(c)(5)(ii)) for both subparts LL and 

MM) were added to subpart A in the 

2009 Final Rule. The EPA finalized 

confidentiality determinations for the 

data elements in the 2011 Final CBI 

Rule (76 FR 30782). We are proposing 

to amend the existing determinations 

because those determinations did not 

take into account situations where the 

data may already be publicly available. 

With respect to subparts RR and UU, 

we are proposing to amend the 

confidentiality determinations for 16 

data elements in subpart RR where 

previously no categorical CBI 

determinations were made and for 12 

data elements in subpart UU where the 

EPA previously determined the data 

elements to be CBI. More specifically, 

we are proposing to change the 

confidentiality determinations for the 16 

Subpart RR and 12 subpart UU data 

elements to ‘‘Not CBI’’ consistent with 

the Argus Leader criteria. 

Subpart RR and UU reporters must 

report the quantities of CO2 received at 

the custody transfer meter. Subpart RR 

reporters must also report the quantities 

of CO2 produced at the separator flow 

meter if they are actively producing oil 

or natural gas or any other fluids. The 

EPA originally proposed that the 

quantities of CO2 received and CO2

produced including the mass and 

volumetric flow and CO2 concentrations 

used to calculate these values would not 

be CBI (77 FR 1434, January 10, 2012). 

Following review of public comment, 

however, the EPA in its final 

rulemaking (77 FR 48072, August 13, 

2012) determined that the quantities of 

CO2 received and CO2 produced could 

contain sensitive information for some 

facilities that report under subparts RR 

and UU, thus presenting the potential 

for competitive harm to the submitter if 

the information was released. At the 

time, the EPA was not aware that this 

information could be found publicly. 

The EPA, therefore, made categorical 

determinations of ‘‘CBI’’ for the 12 

subpart UU data elements and did not 

make categorical determinations for the 

16 subpart RR data elements. 

We have revisited the original 

confidentiality determinations for these 

data elements under the Argus Leader 

standard and have determined that the 

EPA’s original basis for the 

confidentiality determinations is not 

valid. The EPA has now determined that 

company and facility-level data for CO2

received and CO2 produced are often 

available to the public through company 

websites and annual reports, company 

filings with the Securities and Exchange 

Commission, presentations at 

conferences and other events, and thirdparty analyses. In addition, oil and gas 

production to the well level is reported 

to state oil and gas commissions and is 

widely available to the public through 

the commission websites and records as 

well as through third parties. General 

rules-of-thumb for the quantity of CO2

required to produce a barrel of oil are 

often used in the oil and gas industry to 

estimate CO2 quantities received and 

injected. Since the EPA has now found 

that this information is largely publicly 

available, we are determining in the 

proposed rule that the quantities of CO2

received and CO2 produced submitted 

under subparts RR and UU cannot be 

entitled to confidential treatment under 

the standard set forth by the Argus 

Leader decision. 

Refer to Table 5 in the memorandum, 

Proposed Confidentiality 

Determinations and Emission Data 

Designations for Data Elements in 

Proposed Revisions to the Greenhouse 

Gas Reporting Rule, available in the 

docket for this rulemaking (Docket Id. 

No. EPA–HQ–OAR–2019–0424) for a 

list of each of the 33 data elements with 

this status receiving a determination, 

the proposed confidentiality 

determination for each data element, 

and the Agency’s rationale for each 

proposed determination. 

d. Clarification of Previous 

Confidentiality Determinations 

We are clarifying the confidentiality 

determinations previously finalized 

under 40 CFR part 98 for 12 data 

elements currently in subparts A, LL 

(Suppliers of Coal-based Liquid Fuels), 

MM (Suppliers of Petroleum 

Productions), and NN. These 12 data 

elements were added in the 2009 Final 

Rule, and confidentiality determinations 

were finalized in the 2011 Final CBI 

Rule (76 FR 30782). For these 12 data 

elements, there were discrepancies 

regarding the finalized confidentiality 

determinations in the 2011 Final CBI 

Rule (76 FR 30782) between the 

confidentiality determination specified 

in the preamble to the final rule and the 


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171See April 29, 2011 memorandum ‘‘Final Data 

Category Assignments and Confidentiality 

Determinations for Part 98 Reporting Elements,’’ 

available in the docket for this rulemaking, Docket 

Id. No. EPA–HQ–OAR–2019–0424. 

confidentiality determination specified 

in the April 29, 2011 memorandum to 

the rulemaking.171 We are clarifying 

which explanation of the Agency’s 

confidentiality determination for each of 

the 12 data elements was correct, and 

we are providing explanations for the 

discrepancies between the 

determination specified in the preamble 

to the final rule and the supporting 

memorandum. These clarifications do 

not change the EPA’s treatment of these 

12 data elements; the confidentiality 

determinations being clarified are 

consistent with how the EPA has treated 

these reported data since promulgation 

of the May 26, 2011 final rule. This 

clarification will be effective for all 

previous and future reporting years. 

However, due to the conflict in the 

previous rules, we are providing a new 

opportunity to comment on the 

Agency’s treatment of these data. Refer 

to Table 6 in the memorandum, 

Proposed Confidentiality 

Determinations and Emission Data 

Designations for Data Elements in 

Proposed Revisions to the Greenhouse 

Gas Reporting Rule, available in the 

docket for this rulemaking (Docket Id. 

No. EPA–HQ–OAR–2019–0424), for a 

list of the 12 data elements with this 

status, the clarified confidentiality 

determinations for each data element, 

and an explanation of the discrepancy 

in the documentation of their 

confidentiality determinations. 

C. Proposed Reporting Determinations 

for Inputs to Emission Equations 

As discussed in section I.C of the 

preamble to the October 24, 2014 rule 

(79 FR 63750), the EPA organizes data 

assigned to the ‘‘Inputs to Emission 

Equations’’ data category into two 

subcategories. The first subcategory 

includes ‘‘inputs to emission equations’’ 

entered into e-GGRT’s Inputs 

Verification Tool (IVT). These ‘‘inputs 

to emission equations’’ are entered into 

IVT to satisfy the EPA’s verification 

requirements. These data must be 

maintained as records by the submitter, 

but the data are not included in the 

annual report that is submitted to the 

EPA. This is done in circumstances 

where the EPA has determined that the 

‘‘inputs to emission equations’’ meet the 

criteria necessary for them to be entered 

into the IVT system. The second 

subcategory includes ‘‘inputs to 

emission equations’’ that must be 

included in the annual report submitted 

to the EPA. This is done in 

circumstances where the EPA has 

determined that the data elements 

assigned to the ‘‘Inputs to Emission 

Equations’’ category do not meet the 

criteria necessary for them to be entered 

into the IVT system. These ‘‘inputs to 

emission equations,’’ once received by 

the EPA, are not held as confidential. 

As stated in section VI.B.1 of this 

preamble, the EPA is determining that 

the Argus Leader decision does not 

impact our approach for handling of 

data elements assigned to the ‘‘Inputs to 

Emission Equations’’ data category. Data 

assigned to this data category and 

subcategorized by the Agency as ‘‘inputs 

to emission equations’’ entered into IVT 

do not become federal records for the 

purposes of part 98 reporting, so no 

confidentiality determination needs to 

be made for data elements determined 

to fall within this subcategory of data. 

Since this subcategory of data is only 

entered into the IVT system and not in 

the annual report sent directly to the 

EPA, the Argus Leader decision does 

not affect the approach to these data or 

the criteria the Agency uses to 

determine whether these data should be 

considered to fall within this 

subcategory. Likewise, for the same 

reason, the Argus Leader decision does 

not impact actions in previous 

rulemakings designating certain data as 

‘‘inputs to emission equations’’ to be 

entered into the IVT system. 

In continuation of this past approach, 

we are proposing to assign 125 new or 

substantially revised data elements in 

subparts I, W, DD, and SS to the ‘‘Inputs 

to Emission Equations’’ data category. 

Based on our evaluation of each data 

element assigned to the ‘‘Inputs to 

Emission Equations’’ data category, we 

determined that none of these 125 

evaluated data meet the criteria 

necessary for them to be entered into the 

IVT system; therefore, we propose that 

all 125 of these data elements be 

reported to the EPA and would be 

considered ‘‘emission data.’’ These 

‘‘inputs to emission equations’’ once 

received by the EPA would not qualify 

to be held as confidential. Refer to Table 

1 in the memorandum, Proposed 

Reporting Determinations for Data 

Elements Assigned to the Inputs to 

Emission Equations Data Category in 

Proposed Revisions to the Greenhouse 

Gas Reporting Rule, available in the 

docket for this rulemaking (Docket Id. 

No. EPA–HQ–OAR–2019–0424) for a 

list of the 125 data elements proposed 

to be reported that are being designated 

as ‘‘inputs to emission equations,’’ and 

the EPA’s rationale for the proposed 

reporting determinations. The table also 

includes a discussion of the criteria that 

we established in 2011 for evaluating 

whether data assigned to the ‘‘Inputs to 

Emission Equations’’ data category 

should be entered into the IVT system. 

In our evaluation we found that even if 

the 2011 criteria were based on the 

standard for confidential treatment set 

forth in the Supreme Court’s 2019 Argus 

Leader decision, it would not impact 

our determination that these 125 data 

elements should be directly reported to 

EPA instead of entered into IVT. 

Note that this proposal also includes 

proposed revisions to calculation 

methodologies in direct emitter subparts 

G, P, S, and Y that would require 

reporters under these subparts to enter 

new or substantially revised ‘‘inputs to 

emission equations’’ in IVT. These new 

and substantially revised data elements 

are not proposed to be included in the 

reporting section of those subparts but 

would instead be retained as records. 

Since the EPA is not proposing to 

include these data in the annual report, 

the data elements are not included in 

the evaluation discussed in this section. 

Refer to section III of this preamble for 

discussion of all proposed revisions to 

the recordkeeping sections of subparts 

G, P, S, and Y. 

D. Proposed Revision to Confidentiality 

Determinations for Existing 40 CFR Part 

98 Data Elements Affected by the AIM 

Implementation Rule 

On October 5, 2021, the EPA finalized 

the AIM Implementation Rule (86 FR 

55116), which establishes a program to 

phase down hydrofluorocarbon 

production and consumption (hereafter 

referred to as the ‘‘AIM Act’’) at 40 CFR 

part 84 (hereafter referred to as ‘‘Part 

84’’). There are cases where similar or 

identical data will be collected under 

both the AIM Act under Part 84 and the 

GHGRP under part 98. For some of these 

overlapping data, the EPA had 

previously determined under part 98 

that the data would be treated as 

confidential when collected under the 

GHGRP. However, pursuant to the AIM 

Act, the EPA subsequently determined 

that the overlapping data elements 

collected under the AIM Act would not 

be provided confidential treatment. 

Refer to section X.C of the AIM 

Implementation Rule for the Agency’s 

rationale for these determinations (86 

FR 55191). Specifically, the AIM 

Implementation Rule determined that 

12 data elements would not be eligible 

for confidential treatment when 

reported under the AIM Act where the 

data had previously been determined to 

be entitled to confidential treatment 

under the GHGRP. 

To align the GHGRP with the AIM 

Act, we are proposing to amend the 

confidentiality determinations made 


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172See pg. 12 of ‘‘Memorandum—Classification of 

Data Reported Under the HFC Phasedown Rule’’ 

available at Docket Id. No. EPA–HQ–OAR–2021– 

0044–0227 and in the docket to for this rulemaking, 

Docket Id. No. EPA–HQ–OAR–2019–0424. 

under the GHGRP for these 12 

overlapping data elements. As these 12 

data elements are not eligible for 

confidential treatment and will be 

publicly released under the AIM Act, 

there is no basis for treating the data as 

confidential under the GHGRP. 

Therefore, we are proposing that the 

data no longer be entitled to 

confidential treatment when reported 

under the GHGRP. We are proposing to 

amend the confidentiality 

determinations for these 12 overlapping 

data elements for only those reporting 

years that the data are collected under 

the AIM Act and only those GHGs 

covered by the AIM Act. First, regarding 

the reporting years, the EPA has been 

collecting many of these 12 data 

elements under the GHGRP since 2010, 

whereas the EPA will only begin 

collecting data under the AIM Act for 

activities beginning in 2022. Therefore, 

we are not proposing to amend the 

confidentiality determinations for any 

years prior to 2022 that the data were 

collected under the GHGRP. Instead, we 

propose to amend the part 98 

confidentiality determinations 

prospectively, such that these 12 data 

elements would not be treated as 

confidential for the annual reports 

covering RY2022 and future years. 

Second, regarding GHGs, the AIM Act 

requires reporting of 18 GHGs, whereas 

the GHGRP covers a much broader set 

of GHGs. We are proposing to amend 

the part 98 confidentiality 

determinations for these 12 data 

elements only for reported data 

associated with the exact GHGs covered 

under the AIM Act as listed in appendix 

A of part 84. 

The 12 overlapping data elements for 

which we are proposing to amend the 

confidentiality determination include 

data elements currently reported under 

subparts A and OO of part 98. A list of 

these 12 affected data elements and the 

proposed determinations are 

specifically listed in Table 1 in the 

memorandum titled Proposed 

Determinations that would Align the 

Greenhouse Gas Reporting Program with 

the Determinations Made under the AIM 

Act Regulations available in the docket 

for this rulemaking, Docket Id. No. 

EPA–HQ–OAR–2019–0424. 

The AIM Implementation Rule also 

included one HFC data element to be 

used in the administration of the AIM 

Act that is only reported under part 98 

but not under the AIM Act, specifically 

under 40 CFR 98.416(a). This data 

element is ‘‘Annual quantities of 

fluorinated greenhouse gases [other than 

HFCs regulated under the AIM Act], 

identified by type, intentionally 

produced on a facility line that also 

produces HFC-23.’’ 172 The Agency will 

invoke the modification provisions of 40 

CFR 2.301(d)(4) to make an individual 

determination on this specific data 

element. Once that process is 

completed, the Agency may make a 

conforming change to the 

confidentiality determination for that 

data category in the final version of this 

rulemaking. Note that the determination 

affects only fluorinated greenhouse 

gases that are produced on a facility line 

that also produces HFC–23. 

E. Request for Comments on Proposed 

Category Assignments, Confidentiality 

Determinations, or Reporting 

Determinations 

By proposing confidentiality 

determinations prior to data reporting 

through this proposal and rulemaking 

process, we provide potential reporters 

an opportunity to submit comments, 

particularly comments identifying data 

elements proposed by the Agency to be 

‘‘not CBI’’ that reporters consider to be 

customarily and actually treated as 

private. Likewise, we provide potential 

reporters an opportunity to submit 

comments on whether there are 

disclosure concerns for ‘‘inputs to 

emission equations’’ that we propose 

would be included in the annual reports 

and subsequently released by the EPA. 

This opportunity to submit comments is 

intended to provide reporters with the 

opportunity that is afforded to reporters 

when the EPA considers claims for 

confidential treatment of information in 

case-by-case confidentiality 

determinations under 40 CFR part 2. In 

addition, the comment period provides 

an opportunity to respond to the EPA’s 

proposed determinations with more 

information for the Agency to consider 

prior to finalization. We will evaluate 

the comments on our proposed 

determinations, including claims of 

confidentiality and information 

substantiating such claims, before 

finalizing the confidentiality 

determinations. Please note that this 

will be reporters’ only opportunity to 

substantiate a confidentiality claim for 

data elements included in this 

rulemaking where a confidentiality 

determination or reporting 

determination is being proposed. Upon 

finalizing the confidentiality 

determinations and reporting 

determinations of the data elements 

identified in this proposed rule, the EPA 

will release or withhold these data in 

accordance with 40 CFR 2.301(d), which 

contains special provisions governing 

the treatment of part 98 data for which 

confidentiality determinations have 

been made through rulemaking 

pursuant to CAA sections 114 and 

307(d). 

If members of the public have reason 

to believe any data elements in this 

proposed rule that are proposed to be 

treated as confidential are not 

customarily and actually treated as 

private by reporters, please provide 

comment explaining why the Agency 

should not provide an assurance of 

confidential treatment for data. 

When submitting comments regarding 

the confidentiality determinations or 

reporting determinations we are 

proposing in this action, please identify 

each individual proposed new, revised, 

or existing data element you consider to 

be confidential or do not consider to be 

‘‘emission data’’ in your comments. If 

the data element has been designated as 

‘‘emission data,’’ please explain why 

you do not believe the information 

should be considered ‘‘emission data’’ 

as defined in 40 CFR 2.301(a)(2)(i). If the 

data has not been designated as 

‘‘emission data’’ and is proposed to be 

not entitled to confidential treatment, 

please explain specifically how the data 

element is commercial or financial 

information that is both customarily and 

actually treated as private. Particularly 

describe the measures currently taken to 

keep the data confidential and how that 

information has been customarily 

treated by your company and/or 

business sector in the past. This 

explanation is based on the 

requirements for confidential treatment 

set forth in Argus Leader. If the data 

element has been designated as an 

‘‘input to an emission equation’’ (i.e., 

not entitled to confidential treatment), 

please explain specifically why there 

are disclosure concerns. 

Please also discuss how this data 

element may be different from or similar 

to data that are already publicly 

available, including data already 

collected and published annually by the 

GHGRP, as applicable. Please submit 

information identifying any publicly 

available sources of information 

containing the specific data elements in 

question. Data that are already available 

through other sources would likely be 

found not to qualify for confidential 

treatment. In your comments, please 

identify the manner and location in 

which each specific data element you 

identify is publicly available, including 

a citation. If the data are physically 

published, such as in a book, industry 

trade publication, or federal agency 

publication, provide the title, volume 

number (if applicable), author(s), 


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publisher, publication date, and 

International Standard Book Number 

(ISBN) or other identifier. For data 

published on a website, provide the 

address of the website, the date you last 

visited the website and identify the 

website publisher and content author. 

Please avoid conclusory and 

unsubstantiated statements, or general 

assertions regarding the confidential 

nature of the information. 

Finally, we are not proposing new 

confidentiality determinations and 

reporting determinations for data 

reporting elements proposed to be 

unchanged or minimally revised 

because the final confidentiality 

determinations and reporting 

determinations that the EPA made in 

previous rules for these unchanged or 

minimally revised data elements are 

unaffected by this proposed amendment 

and will continue to apply. The 

minimally revised data elements are 

those where we are proposing revisions 

that would not require additional or 

different data to be reported. For 

example, under subpart FF, we are 

proposing to revise a data element to 

clarify the term ‘‘Mine Safety and 

Health Administration (MSHA) 

number’’ to be ‘‘Mine Safety and Health 

Administration (MSHA) identification 

number’’ (see 40 CFR 98.246(t)). This 

proposed change would not impact the 

data collected, and therefore we are not 

proposing a new or revised 

confidentiality determination. However, 

we are soliciting comment on any cases 

where a minor revision would impact 

the previous confidentiality 

determination or reporting 

determination. In your comments, 

please identify the specific data 

element, including name and citation, 

and explain why the minor revision 

would impact the previous 

confidentiality determination or 

reporting determination. 

VII. Impacts of the Proposed 

Amendments 

The EPA is proposing amendments to 

part 98 in order to implement 

improvements to the GHGRP, including 

revisions to update existing emission 

factors and emissions estimation 

methodologies, revisions to require 

reporting of additional data to 

understand new source categories or 

new emission sources for specific 

sectors and address potential gaps in 

reporting, and revisions to collect data 

that would improve the EPA’s 

understanding of the sector-specific 

processes or other factors that influence 

GHG emission rates, verification of 

collected data, or to complement or 

inform other EPA programs. The EPA is 

also proposing revisions that would 

improve implementation of the 

program, such as those that would 

update applicability estimation 

methodologies, provide flexibility for or 

simplifying calculation and monitoring 

methodologies, streamline 

recordkeeping and reporting, and other 

minor technical corrections or 

clarifications identified as a result of 

working with the affected sources 

during rule implementation and 

outreach. The EPA anticipates that the 

proposed revisions would result in an 

overall increase in burden for reporters. 

The proposed revisions would increase 

burden in cases where the proposed 

amendments add or revise reporting 

requirements or require additional 

emissions data to be reported. We 

anticipate a decrease in burden where 

the proposed revisions would 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 proposing changes 

where we anticipate increased clarity or 

more flexibility for reporters that could 

result in a potential decrease in burden, 

but we are unable to quantify this 

decrease. 

As discussed in section V of this 

preamble, we are proposing to 

implement these changes for RY2023 

reports. Costs have been estimated over 

the three years following the year of 

implementation. The incremental 

implementation costs for all subparts for 

each reporting year are summarized in 

Table 6 of this preamble. The estimated 

annual average labor burden is 

$1,417,494 per year. The incremental 

burden by subpart is shown in Table 6 

of this preamble. 

TABLE 6—TOTAL INCREMENTAL LABOR BURDEN FOR REPORTING YEARS 2023–2025 

[$2017/year] 

Cost summary RY2023 RY2024 RY2025 Annual 

average 

Burden by Year (all subparts) ......................................................................... $1,417,591 $1,416,802 $1,418,090 $1,417,494 

There is an additional annual 

incremental burden of $7,281 for capital 

and operation and maintenance (O&M) 

costs, which reflects changes to 

applicability and monitoring for 

subparts I, P, W, UU, and VV. Including 

capital and O&M costs, the total annual 

average burden is $1,424,775 over the 

next 3 years. 

The incremental burden by subpart is 

shown in Table 7 of this preamble. Note 

that subparts with proposed revisions 

that would not result in any changes to 

burden (e.g., subparts FF and NN) are 

excluded from this table. 

TABLE 7—TOTAL INCREMENTAL BURDEN BY SUBPART

[$2017/year] a

Subpart 

Labor costs 

Capital 

and O&M Initial year Subsequent 

years 

C—General Stationary Fuel Combustion Sources 

Facilities Reporting only to Subpart C ......................................................................................... $70,732 $70,732 

Facilities Reporting to Subpart C plus another subpart .............................................................. 94,999 94,999 

G—Ammonia Manufacturing ....................................................................................................... 250 250 

H—Cement Production ................................................................................................................ 3,655 3,655 

I—Electronics Manufacturing b ..................................................................................................... 19,056 17,839 $50 


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TABLE 7—TOTAL INCREMENTAL BURDEN BY SUBPART—Continued 

[$2017/year] a

Subpart 

Labor costs 

Capital 

and O&M Initial year Subsequent 

years 

N—Glass Production ................................................................................................................... 818 818 

P—Hydrogen Production ............................................................................................................. 628 628 (1,536) 

Q—Iron and Steel Production ..................................................................................................... 1,454 1,454 

S—Lime Manufacturing ............................................................................................................... 1,351 1,351 

W—Petroleum and Natural Gas Systems ................................................................................... 1,211,076 1,211,076 8,667 

X—Petrochemical Production ...................................................................................................... 528 528 

Y—Petroleum Refineries ............................................................................................................. 801 801 

BB—Silicon Carbide Production .................................................................................................. 20 20 

DD—Electrical Equipment Use .................................................................................................... 7,106 7,106 

GG—Zinc Production ................................................................................................................... 20 20 

HH—Municipal Solid Waste Landfills .......................................................................................... 3,297 3,297 

OO—Suppliers of Industrial Greenhouse Gases ........................................................................ 810 810 

PP—Suppliers of Carbon Dioxide ............................................................................................... 629 629 

SS—Electrical Equipment Manufacture or Refurbishment ......................................................... 338 338 

UU c .............................................................................................................................................. (1,831) (1,831) (100) 

VVd .............................................................................................................................................. 1,833 3,355 200 

Total e .................................................................................................................................... 1,417,591 1,417,446 7,281 

a Includes estimated increase or decrease in costs following implementation of revisions in RY2023. 

bAverage subsequent year labor costs for Subpart I. Subpart I subsequent year costs include $17,252 in Year 2 and $17,526 in Year 3. 

cAnnual burden includes labor costs and annual O&M savings for two reporters who will begin submitting reports under proposed subpart VV 

in each year. dSubsequent year labor costs include $2,848 in Year 2 and $3,862 in Year 3. O&M costs are based on $100 in Year 1, $200 in Year 2, and 

$300 in Year 3. eSubsequent year labor costs include $1,416,802 in Year 2 and $1,418,090 in Year 3. 

A full discussion of the cost and 

emission impacts may be found in the 

memorandum, Assessment of Burden 

Impacts for Proposed Revisions for the 

Greenhouse Gas Reporting Rule 

available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is a significant regulatory 

action that was submitted to the OMB 

for review. This action involves 

proposed amendments that raise novel 

legal or policy issues. Any changes 

made in response to OMB 

recommendations have been 

documented in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. 

B. Paperwork Reduction Act 

The information collection activities 

in this proposed rule have been 

submitted for approval to the OMB 

under the PRA. The ICR document that 

the EPA prepared has been assigned 

EPA ICR number 2300.19. You can find 

a copy of the ICR in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424, and it is briefly 

summarized here. 

The EPA does not anticipate that the 

proposed amendments would result in 

substantial burden, based on the 

changes to the reporting requirements, 

in any of the subparts for which 

amendments are being proposed. In 

many cases, the proposed amendments 

to the requirements would reduce the 

reporting burden by clarifying or 

improving the estimation methodologies 

for determining applicability, 

simplifying calculation methodologies 

or providing flexibility for monitoring 

requirements, or simplifying the data 

that must be reported. The estimated 

annual average burden is 16,366 hours 

and $1,424,775 over the 3 years covered 

by this information collection. The 

burden costs include $1,424,772 from 

revisions implemented in the first year, 

$1,424,082 from revisions implemented 

in the second year, and $1,425,471 from 

revisions implemented in the third year. 

Further information on the EPA’s 

assessment on the impact on burden can 

be found in the memorandum, 

Assessment of Burden Impacts for 

Proposed Revisions for the Greenhouse 

Gas Reporting Rule 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 under the authority 

provided in CAA section 114. 

Estimated number of respondents: 

10,041 (affected by proposed 

amendments). 

Frequency of response: Annually. 

Total estimated burden: 16,366 hours 

(per year). Burden is defined at 5 CFR 

1320.3(b). 

Total estimated cost: $1,424,775, 

includes $7,281 annualized capital or 

operation & maintenance costs. 

An Agency may not conduct or 

sponsor, and a person is not required to 

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. 

Submit your comments on the 

Agency’s need for this information, the 

accuracy of the provided burden 

estimates and any suggested methods 

for minimizing respondent burden to 

the EPA using the docket identified at 

the beginning of this rule. The EPA will 

respond to any ICR-related comments in 

the final rule. You may also send your 

ICR-related comments to OMB’s Office 

of Information and Regulatory Affairs 

using the interface at https://

www.reginfo.gov/public/do/PRAMain. 

Find this particular information 


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173The original analyses, in section III.D of the 

2011 package (75 FR 74458, November 30, 2010), 

stated, ‘‘smaller enterprises have very small 

operations (such as a single family owning a few 

production wells) that are unlikely to cross the 

25,000 metric tons CO2e reporting threshold.’’ The 

second analysis, in section IV.B of the preamble to 

the 2015 proposed amendments (79 FR 76267; 

December 9, 2014), stated, ‘‘The petroleum and 

natural gas industry has a large number of 

enterprises, the majority of them in the 1–20 

employee range. However, a large fraction of 

production comes from large corporations and not 

those with less than 20 employee enterprises. The 

smaller enterprises in most cases deal with very 

small operations (such as a single family owning a 

few production wells) that are unlikely to cross the 

25,000 metric tons CO2e threshold.’’ 

collection by selecting ‘‘Currently under 

Review—Open for Public Comments’’ or 

by using the search function. OMB must 

receive comments no later than August 

22, 2022. 

C. Regulatory Flexibility Act (RFA) 

I certify that this proposed action 

would 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 businesses 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 an LDC. In the 

promulgation of the rule, the EPA took 

several steps to reduce the impact on 

small entities. For example, the EPA 

determined appropriate thresholds that 

reduced the number of small businesses 

reporting. In addition, the EPA 

conducted several meetings with 

industry associations to discuss 

regulatory options and the 

corresponding burden on industry, such 

as recordkeeping and reporting. Except 

as discussed below, the proposed 

revisions would not revise these 

thresholds for existing subparts, 

therefore, we do not expect any 

additional small entities will be 

impacted under the proposed rule 

revisions. The proposed rule 

amendments predominantly apply to 

existing reporters and are amendments 

that would improve the existing 

emissions estimation methodologies; 

implement requirements to collect 

additional data to understand new 

source categories or emissions sources; 

improve the EPA’s understanding of the 

sector-specific processes or other factors 

that influence GHG emission rates and 

improve verification of collected data; 

and provide additional data to 

complement or inform other EPA 

programs under the CAA and to more 

broadly inform climate programs and 

policies. We are also proposing 

revisions that clarify or update 

provisions that have been unclear, or 

that streamline or simplify 

requirements, for example, by 

increasing flexibility for reporters or 

removing redundant requirements. In 

general, these changes are 

improvements or clarifications of 

requirements that do not require new 

data monitoring and would not 

significantly increase reporter burden, 

or are changes that require data that is 

readily available and may be obtained 

from company records or estimated 

from existing inputs or data elements 

already collected under part 98. 

In evaluating the impacts of the 

proposed revisions, we assessed the 

costs and impacts to small entities in 

three areas, including revisions to 

subpart applicability, changes to 

existing monitoring or calculation 

methodologies, and revisions to 

reporting and recordkeeping 

requirements for data provided to the 

program. First, we evaluated the costs to 

entities who may be affected by changes 

to applicability. In general, this is the 

area that would be most likely to have 

greater impacts, as facilities assume 

substantially higher cost when they 

become newly applicable to the full set 

of requirements under part 98 versus the 

costs associated with an incremental 

change in an existing requirement. Only 

the proposed revisions to applicability 

to subpart I (discussed in section III.E.2 

of this preamble) are anticipated to 

potentially impact new reporters that 

have not previously reported to the 

GHGRP. The SBA size standard for 

facilities falling under the NAICS code 

334413 (Semiconductor and Related 

Device Manufacturing) is 1,250 

employees. In the subpart I initial 

promulgation package, we originally 

assessed the impact of complying with 

subpart I requirements on all small 

entities by calculating a cost-to-sales 

ratio for six enterprise size ranges using 

the average total annualized reporting 

costs to the average annual sales 

receipts for each establishment (85 FR 

74813, December 1, 2010). Based on this 

analysis, the cost-to-sales ratio for all 

entity sizes except for the smallest sized 

enterprises (1 to 20 employee range) was 

less than one percent. The EPA further 

concluded that although the cost-tosales ratio for the 1 to 20 employee 

range for semiconductor and related 

device manufacturing was greater than 

one percent (i.e., 1.16 percent); facilities 

with emissions greater than 25,000 

mtCO2e per year are unlikely to be 

included in the 1 to 20 employees size 

category. Under this proposed action, 

we estimate there is one (1) affected 

facility that does not currently report 

under the GHGRP that may be required 

to report. The affected facility is 

included in the 100 to 499 employee 

range. Although the affected facility 

meets the SBA size standard for a small 

business and would potentially incur 

costs from becoming newly subject the 

GHGRP ($18,736 in the first year and 

$17,032 in subsequent years), the coststo-sales ratio for a facility in this size 

range would be anticipated to be less 

than 0.10%. Therefore, we have 

determined there would not be a 

significant economic impact on a 

substantial number of small entities 

from the proposed revisions to subpart 

I. 

Next, we evaluated the costs and 

impacts to small entities associated with 

revisions to monitoring and calculation 

methodologies to each subpart. For 

those subparts where the EPA is 

proposing revisions to update or 

streamline monitoring and calculation 

methodologies (i.e., subparts C, G, I, P, 

and S), we estimate no change or a 

decrease in burden; therefore, there 

would be no significant economic 

impacts on small entities from these 

proposed revisions. For a subset of 

subpart W reporters, the proposed 

monitoring revisions would result in a 

modest increase in labor costs of $430 

per affected reporter, and $12 operation 

and maintenance costs per reporter. 

Detailed small business analyses were 

performed for subpart W in the initial 

promulgation package from 2011 (75 FR 

74458, November 30, 2010) for the eight 

original industry segments and in the 

2015 amendments to subpart W for 

three additional industry segments (80 

FR 64262, October 22, 2015). Both 

analyses stated that the rule will not 

have a significant economic impact on 

a substantial number of small entities, 

because we concluded that small 

businesses are unlikely be impacted.173

Furthermore, because the costs 

associated with the proposed 

monitoring revisions are minimal, no 

significant small entity impacts are 

anticipated for facilities subject to the 

proposed subpart W amendments. 

Because the EPA does not foresee an 

increase in the number of reporters or 

any changes in the affected industry 


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174EPA Policy on Consultation and Coordination 

with Indian Tribes, May 4, 2011. Available at: 

https://www.epa.gov/sites/default/files/2013-08/ 

documents/cons-and-coord-with-indian-tribespolicy.pdf. 

segments from the proposed revisions, 

we have determined that the previous 

small business analyses still apply and 

there will not be a significant economic 

impact on a substantial number of small 

entities from the proposed revisions to 

monitoring for subpart W. 

Finally, we evaluated the costs 

associated with revisions to 

recordkeeping and reporting, 

specifically revisions to the data 

elements that are reported in e-GGRT or 

entered into IVT, for each subpart (C, G, 

H, I, N, P, Q, S, W, X, Y, BB, DD, GG, 

HH, OO, PP, and SS). Based on the 

detailed small business analyses 

performed for each subpart in the initial 

promulgation packages (74 FR 56370, 

October 10, 2009; 75 FR 39738, July 12, 

2010; 75 FR 75075, December 1, 2010; 

and 75 FR 74813, December 1, 2010), 

the costs associated with the reporting 

program are estimated to be less than 

one percent of sales in all firm size 

categories, with the exception of a small 

number of entities in the 1 to 20 

employee range, which we determined 

to be unlikely to meet the regulatory 

thresholds and unlikely to be covered 

by the rule. With the exception of 

subpart W, the impacts from the 

proposed revisions to reporting and 

recordkeeping in this action for each 

subpart are less than $100 per entity, 

with an average annual burden increase 

of $46 per entity. For subpart C 

reporters, the highest average burden 

increase is $44 per facility. Because 

these costs are minimal, we have 

determined that the proposed revisions 

are unlikely to result in costs exceeding 

more than one percent of sales in any 

firm size category. For subpart W, the 

total annual average costs from the 

proposed revisions to reporting and 

recordkeeping are $412 per facility. 

However, as noted above in this section, 

we do not anticipate any small entities 

are currently subject to or reporting 

under subpart W. Further, the proposed 

revisions to reporting and recordkeeping 

under subpart W are unlikely to result 

in costs exceeding more than one 

percent of sales in any firm size 

category. Therefore, we have 

determined there are no significant 

economic impacts for any potential 

small entities subject to the revisions to 

reporting or recordkeeping 

requirements. 

We have therefore concluded that this 

proposed action will have no significant 

regulatory burden for any directly 

regulated small entities and thus that 

this proposed action would not have a 

significant economic impact on a 

substantial number of small entities. 

Details of this analysis are presented in 

the memorandum, Assessment of 

Burden Impacts for Proposed Revisions 

for the Greenhouse Gas Reporting Rule 

available in the docket for this 

rulemaking, Docket Id. No. EPA–HQ– 

OAR–2019–0424. The EPA continues to 

conduct significant outreach on the 

GHGRP and maintains an ‘‘open door’’ 

policy for stakeholders to help inform 

the EPA’s understanding of key issues 

for the industries. We continue to be 

interested in the potential impacts of the 

proposed rule amendments on small 

entities and welcome comments on 

issues related to such impacts. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This action does not contain an 

unfunded mandate of $100 million or 

more as described in UMRA, 2 U.S.C. 

1531–1538, and does not significantly or 

uniquely affect small governments. The 

action implements mandate(s) 

specifically and explicitly set forth in 

CAA section 114(a)(1) without the 

exercise of any policy discretion by the 

EPA. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action has tribal implications. 

However, it will neither impose 

substantial direct compliance costs on 

federally recognized tribal governments, 

nor preempt tribal law. This regulation 

will apply directly to stationary 

combustion units, cement production 

facilities, landfills, and petroleum and 

natural gas facilities that may be owned 

by tribal governments that emit GHGs. 

However, it will only have tribal 

implications where the tribal entity 

owns a facility that directly emits GHGs 

above threshold levels; therefore, 

relatively few (approximately 8) tribal 

facilities would be affected. This 

regulation is not anticipated to impact 

facilities or suppliers of additional 

sectors owned by tribal governments. 

Further, the proposed rule amendments 

are amendments that would improve the 

existing emissions estimation 

methodologies; implement requirements 

to collect additional data to understand 

new source categories or new emission 

sources for specific sectors; improve the 

EPA’s understanding of the sectorspecific processes or other factors that 

influence GHG emission rates and 

improve verification of collected data; 

provide additional data to complement 

or inform other EPA programs; clarify or 

update provisions that have been 

unclear; or that streamline or simplify 

requirements. In general, these changes 

are improvements or clarifications of 

requirements that for the most part 

would not require new equipment, 

sampling, or monitoring, and instead, 

would only require reporters to provide 

data that is readily available and may be 

obtained from company records or 

estimated from existing inputs or data 

elements already collected under part 

98. Therefore, these proposed changes 

do not significantly change the part 98 

requirements that may apply to tribal 

facilities because they generally do not 

require new equipment, sampling, or 

monitoring, and would not substantially 

increase reporter burden, impose 

significant direct compliance costs for 

tribal facilities, or preempt tribal law. 

Although few facilities subject to part 

98 are likely to be owned by tribal 

governments, the EPA previously sought 

opportunities to provide information to 

tribal governments and representatives 

during the development of the proposed 

and final rules for part 98 subparts that 

were promulgated on October 30, 2009 

(74 FR 52620), July 12, 2010 (75 FR 

39736), November 30, 2010 (75 FR 

74458), and December 1, 2010 (75 FR 

74774 and 75 FR 75076). Consistent 

with the 2011 EPA Policy on 

Consultation and Coordination with 

Indian Tribes,174 the EPA previously 

consulted with tribal officials early in 

the process of developing part 98 

regulations to permit them to have 

meaningful and timely input into its 

development and to provide input on 

the key regulatory requirements 

established for these facilities. A 

summary of these consultations is 

provided in section VIII.F of the 

preamble to the final rule published on 

October 30, 2009 (74 FR 52620), section 

V.F of the preamble to the final rule 

published on July 12, 2010 (75 FR 

39736), section IV.F of the preamble to 

the re-proposal of subpart W (Petroleum 

and Natural Gas Systems) published on 

April 12, 2010 (75 FR 18608), section 

IV.F of the preambles to the final rules 

published on December 1, 2010 (75 FR 

74774 and 75 FR 75076). As described 

in this section, the proposed rule does 

not significantly revise the established 

regulatory requirements and would not 


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substantially change the equipment, 

monitoring, or reporting activities 

conducted by these facilities, or result 

in other substantial impacts for tribal 

facilities. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets Executive Order 

13045 as applying only to those 

regulatory actions that concern 

environmental health or safety risks that 

the EPA has reason to believe may 

disproportionately affect children, per 

the definition of ‘‘covered regulatory 

action’’ in section 2–202 of the 

Executive Order. This action is not 

subject to Executive Order 13045 

because it does not concern an 

environmental health risk or safety risk. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not a ‘‘significant 

energy action’’ because it is not likely to 

have a significant adverse effect on the 

supply, distribution or use of energy. 

The proposed amendments would 

improve the existing emissions 

estimation methodologies; implement 

requirements to collect additional data 

to understand new source categories or 

new emission sources for specific 

sectors; improve the EPA’s 

understanding of factors that influence 

GHG emission rates; improve 

verification of collected data; and 

provide additional data to complement 

or inform other EPA programs. We are 

also proposing revisions that clarify or 

update provisions that have been 

unclear, or that streamline or simplify 

requirements, alleviate burden through 

revision, simplification, or removal of 

certain calculation, monitoring, 

recordkeeping, or reporting 

requirements. In general, these changes 

would not substantially impact the 

supply, distribution, or use of energy. In 

addition, the EPA is proposing 

confidentiality determinations for new 

and revised data elements proposed in 

this rulemaking and for certain existing 

data elements for which a 

confidentiality determination has not 

previously been proposed, or where the 

EPA has determined that the current 

determination is no longer appropriate. 

These proposed amendments and 

confidentiality determinations do not 

make any changes to the existing 

monitoring, calculation, and reporting 

requirements under part 98 that would 

affect the supply, distribution, or use of 

energy. 

I. National Technology Transfer and 

Advancement Act and 1 CFR Part 51 

This action involves technical 

standards. The EPA proposes to allow 

the use of an alternate method, ASTM 

E415–17, Standard Test Method for 

Analysis of Carbon and Low-Alloy Steel 

by Spark Atomic Emission Spectrometry 

(2017), for the purposes of subpart Q 

(Iron and Steel Production) monitoring 

and reporting. The EPA currently allows 

for the use of standard methods based 

on atomic emission spectrometry in 

other sections of part 98, including 

under 40 CFR 98.144(b) where it can be 

used to determine the composition of 

coal, coke, and solid residues from 

combustion processes by glass 

production facilities. Therefore, the EPA 

is allowing ASTM E415–17 to be used 

in subpart Q. ASTM E415–17 uses spark 

atomic emission vacuum spectrometry 

to determine 21 alloying and residual 

elements in carbon and low-alloy steels. 

The method is designed for chill-cast, 

rolled, and forged specimens. Anyone 

may access the standards on the ASTM 

website (https://www.astm.org/) for 

additional information. These standards 

are available to everyone at a cost 

determined by the ASTM ($50). The 

ASTM also offers memberships or 

subscriptions that allow unlimited 

access to their methods. The cost of 

obtaining these methods is not a 

significant financial burden, making the 

methods reasonably available for 

reporters. The EPA is also proposing to 

add new subpart VV for certain EOR 

operations that choose to use the ISO 

standard designated as CSA/ANSI ISO 

27916:2019, Carbon Dioxide Capture, 

Transportation and Geological 

Storage—Carbon Dioxide Storage Using 

Enhanced Oil Recovery (CO2–EOR) 

(2019), as a means of quantifying 

geologic sequestration. The method 

quantifies CO2 that is stored in 

association with EOR operations, 

focusing on the safe, long-term 

containment of CO2 within the EOR 

complex. CSA/ANSI ISO 27916:2019 

identifies and quantifies CO2 losses 

(including fugitive emissions) and 

quantifies the amount of CO2 stored in 

association with the CO2–EOR project. 

It also shows how allocation rations can 

be used to account for the 

anthropogenic portion of the stored CO2. 

Anyone may access the standard on the 

ANSI/ISO website (https://

webstore.ansi.org/SDO/ISO/) for 

additional information. The standard is 

available to everyone at a cost 

determined by ANSI/ISO ($225). ANSI/ 

ISO also offers memberships or 

subscriptions for reduced costs. Because 

the proposed standard is optional, the 

cost of obtaining this standard is not a 

significant financial burden. The EPA 

will also make a copy of these 

documents available in hard copy at the 

appropriate EPA office (see the FOR

FURTHER INFORMATION CONTACT section of 

this preamble for more information) for 

review purposes only. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

The EPA believes the human health or 

environmental risk addressed by this 

action will not have potential 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income or indigenous 

populations as it does not affect the 

level of protection provided to human 

health or the environment because it is 

a rule addressing information collection 

and reporting procedures. 

K. Determination Under CAA Section 

307(d) 

Pursuant to CAA section 307(d)(1)(V), 

the Administrator determines that this 

action is subject to the provisions of 

CAA section 307(d). Section 

307(d)(1)(V) of the CAA provides that 

the provisions of CAA section 307(d) 

apply to ‘‘such other actions as the 

Administrator may determine.’’ 

List of Subjects 

40 CFR Part 9 

Environmental protection, 

Administrative practice and procedure, 

Reporting and recordkeeping 

requirements 

40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Incorporation by 

reference, Reporting and recordkeeping 

requirements, Suppliers. 

Michael S. Regan, 

Administrator. 

For the reasons stated in the 

preamble, the Environmental Protection 

Agency proposes to amend title 40, 

chapter I, of the Code of Federal 

Regulations as follows: 

PART 9—OMB APPROVALS UNDER 

THE PAPERWORK REDUCTION ACT 

■ 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, 


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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. 

■ 2. Amend § 9.1 by adding an 

undesignated center heading and an 

entry for ‘‘98.1–98.489’’ in numerical 

order to read as follows: 

§ 9.1 OMB approvals under the Paperwork 

Reduction Act. 

* * * * * 

40 CFR citation OMB control 

No. 

* * * * * 

Mandatory Greenhouse Gas Reporting 

98.1–98.489 .......................... 2060–0629 

* * * * * 

PART 98—MANDATORY 

GREENHOUSE GAS REPORTING 

■ 3. The authority citation for part 98 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—General Provision 

■ 4. Amend § 98.1 by revising paragraph 

(c) to read as follows: 

§ 98.1 Purpose and scope. 

* * * * * 

(c) For facilities required to report 

under onshore petroleum and natural 

gas production under subpart W of this 

part, the terms Owner and Operator 

used in this subpart have the same 

definition as Onshore petroleum and 

natural gas production owner or 

operator, as defined in § 98.238. For 

facilities required to report under 

onshore petroleum and natural gas 

gathering and boosting under subpart W 

of this part, the terms Owner and 

Operator used in this subpart have the 

same definition as Gathering and 

boosting system owner or operator, as 

defined in § 98.238. For facilities 

required to report under onshore natural 

gas transmission pipeline under subpart 

W of this part, the terms Owner and 

Operator used in this subpart have the 

same definition as Onshore natural gas 

transmission pipeline owner or operator, 

as defined in § 98.238. 

■ 5. Amend § 98.2 by revising 

paragraphs (f)(1) and (i)(1) and (2) and 

adding paragraph (k) to read as follows: 

§ 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 

§ 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 

§ 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 

§ 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 

§ 98.3(g) for each of the three 

consecutive years and retain such 

records for three years prior to 

notification of discontinuation of 

reporting following the year that 

reporting was discontinued. The owner 

or operator must resume reporting if 

annual CO2e emissions, calculated in 

accordance with paragraph (b)(4) of this 

section, in any future calendar year 

increase to 25,000 metric tons CO2e per 

year or more. 

* * * * * 

(k) To calculate GHG quantities for 

comparison to the 25,000 metric ton 

CO2e per year threshold under 

paragraph (a)(4) of this section for 

facilities that destroy fluorinated GHGs 

or fluorinated heat transfer fluids, the 

owner or operator shall calculate the 

mass in metric tons per year of CO2e 

destroyed as described in paragraphs 

(k)(1) through (k)(3) of this section. 

(1) Calculate the mass in metric tons 

per year of each fluorinated GHG or 

fluorinated heat transfer fluid that is 

destroyed during the year. 

(2) Convert the mass of each 

destroyed fluorinated GHG or 

fluorinated heat transfer fluid from 

paragraph (k)(1) of this section to metric 

tons of CO2e using Equation A–1 of this 

section. 

(3) Sum the total annual metric tons 

of CO2e in paragraph (k)(2) of this 

section for all destroyed fluorinated 

GHGs and destroyed fluorinated heat 

transfer fluids. 

■ 6. Amend § 98.3 by revising 

paragraphs (b)(2) and (h)(4) to read as 

follows: 

§ 98.3 What are the general monitoring, 

reporting, recordkeeping and verification 

requirements of this part? 

* * * * * 

(b) * * * 

(2) For a new facility or supplier that 

begins operation on or after January 1, 

2010 and becomes subject to the rule in 

the year that it becomes operational, 

report emissions starting the first 

operating month and ending on 

December 31 of that year. Each 

subsequent annual report must cover 

emissions for the calendar year, 

beginning on January 1 and ending on 

December 31. 

* * * * * 

(h) * * * 

(4) Notwithstanding paragraphs (h)(1) 

and (2) of this section, upon request by 

the owner or operator, the 

Administrator may provide reasonable 

extensions of the 45-day period for 

submission of the revised report or 

information under paragraphs (h)(1) and 

(2). If the Administrator receives a 

request for extension of the 45-day 

period, by email to an address 

prescribed by the Administrator prior to 

the expiration of the 45-day period, the 

extension request is deemed to be 

automatically granted for 30 days. The 

Administrator may grant an additional 

extension beyond the automatic 30-day 

extension if the owner or operator 

submits a request for an additional 

extension and the request is received by 


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the Administrator prior to the expiration 

of the automatic 30-day extension, 

provided the request demonstrates that 

it is not practicable to submit a revised 

report or information under paragraphs 

(h)(1) and (2) within 75 days. The 

Administrator will approve the 

extension request if the request 

demonstrates to the Administrator’s 

satisfaction that it is not practicable to 

collect and process the data needed to 

resolve potential reporting errors 

identified pursuant to paragraph (h)(1) 

or (2) within 75 days. The Administrator 

will only approve an extension request 

for a total of 180 days after the initial 

notification of a substantive error. 

* * * * * 

■ 7. Amend § 98.4 by revising paragraph 

(h) and adding paragraph (n) to read as 

follows: 

§ 98.4 Authorization and responsibilities of 

the designated representative. 

* * * * * 

(h) Changes in owners and operators. 

Except as provided in paragraph (n) of 

this section, in the event an owner or 

operator of the facility or supplier is not 

included in the list of owners and 

operators in the certificate of 

representation under this section for the 

facility or supplier, such owner or 

operator shall be deemed to be subject 

to and bound by the certificate of 

representation, the representations, 

actions, inactions, and submissions of 

the designated representative and any 

alternate designated representative of 

the facility or supplier, as if the owner 

or operator were included in such list. 

Within 90 days after any change in the 

owners and operators of the facility or 

supplier (including the addition of a 

new owner or operator), the designated 

representative or any alternate 

designated representative shall submit a 

certificate of representation that is 

complete under this section except that 

such list shall be amended to reflect the 

change. If the designated representative 

or alternate designated representative 

determines at any time that an owner or 

operator of the facility or supplier is not 

included in such list and such exclusion 

is not the result of a change in the 

owners and operators, the designated 

representative or any alternate 

designated representative shall submit, 

within 90 days of making such 

determination, a certificate of 

representation that is complete under 

this section except that such list shall be 

amended to include such owner or 

operator. 

* * * * * 

(n) Alternative provisions for changes 

in owners and operators for industry 

segments with a unique definition of 

facility as defined in § 98.238. When 

there is a change to the owner or 

operator of a facility required to report 

under the onshore petroleum and 

natural gas production, natural gas 

distribution, onshore petroleum and 

natural gas gathering and boosting, or 

onshore natural gas transmission 

pipeline industry segments of subpart W 

of this part, or a change to the owner or 

operator for some emission sources from 

the facility in one of these industry 

segments, the provisions specified in 

paragraphs (n)(1) through (4) of this 

section apply for the respective type of 

change in owner or operator and the 

provisions specified in paragraph (n)(5) 

of this section apply to all types of 

change in owner or operator for such 

facilities. 

(1) If the entire facility is acquired by 

an owner or operator that does not 

already have a reporting facility in the 

same industry segment and basin (for 

onshore petroleum and natural gas 

production or onshore petroleum and 

natural gas gathering and boosting) or 

state (for natural gas distribution), a 

certificate of representation that is 

complete under this section shall be 

submitted to reflect the new owner or 

operator within 90 days after the change 

in the owner or operator and according 

to the procedure specified in paragraph 

(b) of this section. If the new owner or 

operator already had emission sources 

listed in the applicable paragraph of 

§ 98.232 prior to the acquisition in the 

same basin (for onshore petroleum and 

natural gas production or onshore 

petroleum and natural gas gathering and 

boosting) or state (for natural gas 

distribution) as the acquired facility but 

had not previously met the applicability 

requirements in § 98.2(a) and § 98.231, 

then per the applicable definition of 

facility in § 98.238, the previously 

owned applicable emission sources 

must be included in the acquired 

facility. The new owner or operator and 

the new designated representative shall 

be responsible for submitting the annual 

report for the facility for the entire 

reporting year beginning with the 

reporting year in which the acquisition 

occurred. 

(2) If the entire facility is acquired by 

an owner or operator that already has a 

reporting facility in the same industry 

segment and basin (for onshore 

petroleum and natural gas production or 

onshore petroleum and natural gas 

gathering and boosting) or state (for 

natural gas distribution), the new owner 

or operator shall merge the acquired 

facility with their existing facility for 

purposes of the annual GHG report. 

Within 90 days after the change in the 

owner or operator, a certificate of 

representation that is complete under 

this section shall be submitted for the 

acquired facility to reflect the new 

owner or operator. The owner or 

operator shall also follow the provisions 

of § 98.2(i)(6) to notify EPA that the 

acquired facility will discontinue 

reporting and shall provide the e-GGRT 

identification number of the merged, or 

reconstituted, facility. The owner or 

operator of the merged facility shall be 

responsible for submitting the annual 

report for the merged facility for the 

entire reporting year beginning with the 

reporting year in which the acquisition 

occurred. 

(3) If only some emission sources 

from the facility are acquired by one or 

more new owners or operators, the 

existing owner or operator (i.e., the 

owner or operator of the portion of the 

facility that is not sold) shall continue 

to report under subpart W of this part 

for the retained emission sources unless 

and until that facility meets one of the 

criteria in § 98.2(i). Each owner or 

operator that acquires emission sources 

from the facility must account for those 

acquired emission sources according to 

paragraph (n)(3)(i) or (ii) of this section, 

as applicable. 

(i) If the purchasing owner or operator 

that acquires only some of the emission 

sources from the existing facility does 

not already have a reporting facility in 

the same industry segment and basin 

(for onshore petroleum and natural gas 

production or onshore petroleum and 

natural gas gathering and boosting) or 

state (for natural gas distribution), the 

purchasing owner or operator shall 

begin reporting as a new facility. The 

new facility must include the acquired 

emission sources listed in the applicable 

paragraph of § 98.232 and any emission 

sources the purchasing owner or 

operator already owned in the same 

industry segment and basin (for onshore 

petroleum and natural gas production or 

onshore petroleum and natural gas 

gathering and boosting) or state (for 

natural gas distribution). The designated 

representative for the new facility must 

be selected by the purchasing owner or 

operator according to the schedule and 

procedure specified in paragraphs (b) 

through (d) of this section. The 

purchasing owner or operator shall be 

responsible for submitting the annual 

report for the new facility for the entire 

reporting year beginning with the 

reporting year in which the acquisition 

occurred. 

(ii) If the purchasing owner or 

operator that acquires only some of the 

emission sources from the existing 

facility already has a reporting facility 

in the same industry segment and basin 

(for onshore petroleum and natural gas 


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production or onshore petroleum and 

natural gas gathering and boosting) or 

state (for natural gas distribution), then 

per the applicable definition of facility 

in § 98.238, the purchasing owner or 

operator must add the acquired 

emission sources listed in the applicable 

paragraph of § 98.232 to their existing 

facility for purposes of reporting under 

subpart W. The purchasing owner or 

operator shall be responsible for 

submitting the annual report for the 

entire facility, including the acquired 

emission sources, for the entire 

reporting year beginning with the 

reporting year in which the acquisition 

occurred. 

(4) If all the emission sources from a 

facility are sold to multiple owners or 

operators, such that the current owner 

or operator of the existing facility does 

not retain any of the emission sources, 

then the current owner or operator of 

the existing facility shall notify EPA 

within 90 days of the transaction that all 

of the facility’s emission sources were 

acquired by multiple purchasers. Each 

owner or operator that acquires 

emission sources from a facility shall 

account for those sources according to 

paragraph (n)(3)(i) or (ii) of this section, 

as applicable. 

(5) Each owner or operator involved 

in a transaction that results in a change 

to the owner or operator of a facility 

shall, as part of the acquisition 

agreement or ownership transfer 

contract, agree upon the entity who will 

be responsible for revisions to annual 

GHG reports under § 98.3(h) for 

reporting years prior to the reporting 

year in which the transaction occurred. 

That responsible entity will select a 

representative who will submit 

revisions to annual GHG reports under 

§ 98.3(h) for that facility. If the selected 

individual is not the designated 

representative for the facility, the 

individual must be designated as the 

alternate designated representative or an 

agent for the facility. 

■ 8. Amend § 98.6 by: 

■ a. Revising the definitions for ‘‘Carbon 

dioxide stream’’, ‘‘Dehydrator’’, and 

‘‘Dehydrator vent emissions;’’ 

■ b. Removing the definition for 

‘‘Desiccant’’; 

■ c. Adding a definition for ‘‘Direct air 

capture (DAC)’’ in alphabetical order; 

and 

■ d. Revising the definition for ‘‘Vapor 

recovery system’’. 

The revisions and addition read 

follows: 

§ 98.6 Definitions. 

* * * * * 

Carbon dioxide stream means carbon 

dioxide that has been captured from an 

emission source (e.g., a power plant or 

other industrial facility, captured from 

ambient air (e.g., direct air capture), or 

extracted from a carbon dioxide 

production well plus incidental 

associated substances either derived 

from the source materials and the 

capture process or extracted with the 

carbon dioxide. 

* * * * * 

Dehydrator means a device in which 

a liquid absorbent (e.g., ethylene glycol, 

diethylene glycol, or triethylene glycol) 

directly contacts a natural gas stream to 

absorb water vapor. 

Dehydrator vent emissions means 

natural gas and CO2 released from a 

natural gas dehydrator system absorbent 

(typically glycol) regenerator and, if 

present, a flash tank separator, to the 

atmosphere, flare, regenerator fire-box/ 

fire tubes, or vapor recovery system. 

Emissions include stripping natural gas 

and motive natural gas used in 

absorbent circulation pumps. 

* * * * * 

Direct air capture (DAC), with respect 

to a facility, technology, or system, 

means that the facility, technology, or 

system uses carbon capture equipment 

to capture carbon dioxide directly from 

the air. Direct air capture does not 

include any facility, technology, or 

system that captures carbon dioxide: 

(1) That is deliberately released from 

a naturally occurring subsurface spring 

or 

(2) Using natural photosynthesis. 

* * * * * 

Vapor recovery system means any 

equipment located at the source of 

potential gas emissions to the 

atmosphere or to a flare, that is 

composed of piping, connections, and, 

if necessary, flow-inducing devices, and 

that is used for routing the gas back into 

the process as a product and/or fuel. For 

purposes of § 98.233, routing emissions 

from a dehydrator regenerator still vent 

or flash tank separator vent to a 

regenerator fire-box/fire tubes does not 

meet the definition of vapor recovery 

system. 

* * * * * 

■ 9. Amend § 98.7 as follows: 

■ a. Revise the introductory text; 

■ b. In paragraph (c)(1), remove the text 

‘‘, incorporation by reference (IBR)’’ and 

add, in its place, the text ‘‘; IBR’’; 

■ c. Redesignate paragraph (e)(38) as 

paragraph (e)(39); 

■ d. Add new paragraph (e)(38) and 

paragraph (g)(6); and 

■ e. In addition to the previous 

amendments to this section, remove the 

text ‘‘, IBR’’ and add, in its place, the 

text ‘‘; IBR’’ wherever it appears 

throughout this section. 

The revision and additions read as 

follows: 

§ 98.7 What standardized methods are 

incorporated by reference into this part? 

Certain material is incorporated by 

reference into this part with the 

approval of the Director of the Federal 

Register under 5 U.S.C. 552(a) and 1 

CFR part 51. To enforce any edition 

other than that specified in this section, 

the EPA must publish a document in the 

Federal Register and the material must 

be available to the public. All approved 

incorporation by reference (IBR) 

material is available for inspection at 

the EPA and at the National Archives 

and Records Administration (NARA). 

Contact EPA at: EPA Docket Center, 

Public Reading Room, EPA WJC West, 

Room 3334, 1301 Constitution Ave. NW, 

Washington, DC; phone: 202–566–1744. 

For information on the availability of 

this material at NARA, email 

fr.inspection@nara.gov, or go to 

www.archives.gov/federal-register/cfr/ 

ibr-locations.html. The material may be 

obtained from the following source(s): 

* * * * * 

(e) * * * 

(38) ASTM E415–17, Standard Test 

Method for Analysis of Carbon and 

Low-Alloy Steel by Spark Atomic 

Emission Spectrometry; IBR approved 

for § 98.174(b). 

* * * * * 

(g) * * * 

(6) CSA/ANSI ISO 27916:19, Carbon 

dioxide capture, transportation and 

geological storage—Carbon dioxide 

storage using enhanced oil recovery 

(CO2-EOR). Edition 1. January 2019; IBR 

approved for §§ 98.480(a), 98.481(a) and 

(b), 98.482, 98.483, 98.484, 98.485, 

98.486(g), 98.487, 98.488(a)(5), and 

98.489. 

* * * * * 

■ 10. Amend table A–1 to subpart A of 

part 98 by: 

■ a. Adding under the heading ‘‘Other 

Fluorinated Compounds’’ the entry 

‘‘Carbonyl fluoride’’ after the entry ‘‘2- 

Bromo-2-chloro-1,1,1-trifluoroethane 

(Halon-2311/Halothane);’’ 

■ b. Removing the heading ‘‘Fluorinated 

GHG Group d’’ and adding in its place 

the heading ‘‘Fluorinated GHG Group e’’ 

■ c. Revising the entry ‘‘Unsaturated 

perfluorocarbons (PFCs), unsaturated 

HFCs, unsaturated 

hydrochlorofluorocarbons (HCFCs), 

unsaturated halogenated ethers, 

unsaturated halogenated esters, 

fluorinated aldehydes, and fluorinated 

ketones’’ under the revised heading 

‘‘Fluorinated GHG Group; e’’ 

■ d. Redesignating footnote ‘‘d’’ as 

footnote ‘‘e;’’ and 


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■ e. Adding new footnote ‘‘d’’ and 

footnote ‘‘f.’’ 

The additions and revisions read as 

follows: 

* * * * * 

TABLE A–1 TO SUBPART A OF PART 98—GLOBAL WARMING POTENTIALS

Name CAS No. Chemical formula 

Global 

warming 

potential 

(100 yr.) 

*******

Other Fluorinated Compounds 

*******

Carbonyl fluoride ........................................................... 353–50–4 COF2 ............................................................................ d 0.14 

Fluorinated GHG Group e

*******

Unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated hydrochlorofluorocarbons (HCFCs), unsaturated halogenated ethers, unsaturated halogenated esters, unsaturated bromofluorocarbons, unsaturated chlorofluorocarbons, unsaturated bromochlorofluorocarbons, unsaturated hydrobromofluorocarbons, unsaturated hydrobromochlorofluorocarbons, 

fluorinated aldehydes, and fluorinated ketones f

1 

* * * * * * * 

* * * * * 

dThis compound was added to Table A–1 in the final rule published on [Date of publication of the final rule in the FEDERAL REGISTER] and effective on January 1, 2023. eFor electronics manufacturing (as defined in § 98.90), the term ‘‘fluorinated GHGs’’ in the definition of each fluorinated GHG group in § 98.6 

shall include fluorinated heat transfer fluids (as defined in § 98.98), whether or not they are also fluorinated GHGs. fThis fluorinated GHG group was updated in the final rule published on [Date of publication of the final rule in the Federal Register] and effective on January 1, 2023. 

■ 11. Amend table A–3 to subpart A of 

part 98 by: 

■ a. Revising the entry ‘‘Electrical 

transmission and distribution 

equipment use at facilities where the 

total nameplate capacity of SF6 and PFC 

containing equipment exceeds 17,820 

pounds, as determined under § 98.301 

(subpart DD).’’; 

■ b. Removing the entry for ‘‘Electrical 

transmission and distribution 

equipment manufacture or 

refurbishment (subpart SS).’’; and 

■ c. Adding the entry ‘‘Geologic 

Sequestration of Carbon Dioxide with 

Enhanced Oil Recovery Using ISO 

27916 (subpart VV).’’ at the end of the 

table. 

The revision and addition read as 

follows: 

* * * * * 

TABLE A–3 TO SUBPART A OF PART 98—SOURCE CATEGORY LIST FOR § 98.2(a)(1) 

*******

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

Electrical transmission and distribution equipment use at facilities where the total estimated emissions from fluorinated GHGs, as determined 

under § 98.301 (subpart DD), are equivalent to 25,000 metric tons CO2e or more per year. 

* * * * * * * 

Geologic Sequestration of Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916 (subpart VV). 

aSource categories are defined in each applicable subpart. 

* * * * * 

■ 12. Amend table A–4 to subpart A of 

part 98 by adding the entry ‘‘Electrical 

transmission and distribution 

equipment manufacture or 

refurbishment, as determined under 

§ 98.451 (subpart SS).’’ after the entry 

‘‘Industrial wastewater treatment 

(subpart II).’’ to read as follows: 

TABLE A–4 TO SUBPART A OF PART 98—SOURCE CATEGORY LIST FOR § 98.2(a)(2) 

*******

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

* * * * * * * 

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


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TABLE A–4 TO SUBPART A OF PART 98—SOURCE CATEGORY LIST FOR § 98.2(a)(2)—Continued 

*******

aSource categories are defined in each applicable subpart. 

* * * * * 

Subpart C—General Stationary Fuel 

Combustion Sources 

■ 13. Amend § 98.33 by: 

■ a. Revising parameters ‘‘CC’’ and 

‘‘MW’’ of Equation C–5 in paragraph 

(a)(3)(iii) introductory text; 

■ b. Adding paragraphs (a)(3)(iii)(A) and 

(B); 

■ c. Revising paragraph (b)(1)(vii); 

■ d. Revising parameter ‘‘EF’’ of 

Equations C–8 in paragraph (c)(1) 

introductory text, C–8a in paragraph 

(c)(1)(i), C–8b in paragraph (c)(1)(ii), C– 

9a in paragraph (c)(2), C–9b in 

paragraph (c)(3), and C–10 in paragraph 

(c)(4) introductory text; 

■ e. Revising paragraphs (c)(6)(i), 

(c)(6)(ii) introductory text, and 

(c)(6)(ii)(A) and (C); 

■ f. Removing and reserving paragraph 

(c)(6)(ii)(B); 

■ g. Revising parameter ‘‘R’’ of Equation 

C–11 in paragraph (d)(1); and 

■ h. Revising the introductory text of 

paragraphs (e), (e)(1), (e)(2)(v), and (e)(3) 

and paragraph (e)(3)(iv). 

The additions and revisions read as 

follows: 

§ 98.33 Calculating GHG emissions. 

* * * * * 

(a) * * * 

(3) * * * 

(iii) * * * 

CC = Annual average carbon content of the 

gaseous fuel (kg C per kg of fuel). The 

annual average carbon content shall be 

determined using the procedures 

specified in paragraphs (a)(3)(iii)(A)(1) 

and (a)(3)(iii)(A)(2) of this section. 

MW = Annual average molecular weight of 

the gaseous fuel (kg per kg-mole). The 

annual average molecular weight shall be 

determined using the procedures 

specified in paragraphs (a)(3)(iii)(A)(3) 

and (a)(3)(iii)(A)(4) of this section. 

* * * * * 

(A) The minimum required sampling 

frequency for determining the annual 

average carbon content (e.g., monthly, 

quarterly, semi-annually, or by lot) is 

specified in § 98.34. The method for 

computing the annual average carbon 

content for Equation C–5 is a function 

of unit size and how frequently you 

perform or receive from the fuel 

supplier the results of fuel sampling for 

carbon content. The methods are 

specified in paragraphs (a)(3)(iii)(A)(1) 

and (2) of this section, as applicable. 

(1) If the results of fuel sampling are 

received monthly or more frequently, 

then for each unit with a maximum 

rated heat input capacity greater than or 

equal to 100 mmBtu/hr (or for a group 

of units that includes at least one unit 

of that size), the annual average carbon 

content for Equation C–5 shall be 

calculated using Equation C–5a of this 

section. If multiple carbon content 

determinations are made in any month, 

average the values for the month 

arithmetically. 

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 § 98.6. 

Use 849.5 scf per kg-mole if you select 

68 °F as standard temperature and 836.6 

scf per kg-mole if you select 60 °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 § 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 § 98.34. The method for 

computing the annual average 

molecular weight for Equation C–5 is a 

function of unit size and how frequently 

you perform or receive from the fuel 

supplier the results of fuel sampling for 

molecular weight. The methods are 

specified in paragraphs (a)(3)(iii)(B)(1) 

and (a)(3)(iii)(B)(2) of this section, as 

applicable. 

(1) If the results of fuel sampling are 

received monthly or more frequently, 

then for each unit with a maximum 

rated heat input capacity greater than or 

equal to 100 mmBtu/hr (or for a group 

of units that includes at least one unit 

of that size), the annual average 

molecular weight for Equation C–5 shall 

be calculated using Equation C–5b of 

this section. If multiple molecular 

weight determinations are made in any 

month, average the values for the month 

arithmetically. 

Where: (MW)annual = Weighted annual average 

molecular weight of the fuel (kg per kgmole). 

(MW)i = Measured molecular weight of the 

fuel, for sample period ‘‘i’’ (which may 

be the arithmetic average of multiple 


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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 § 98.6. 

Use 849.5 scf per kg-mole if you select 

68 °F as standard temperature and 836.6 

scf per kg-mole if you select 60 °F as 

standard temperature. 

n = Number of sample periods in the year. 

(2) If the results of fuel sampling are 

received less frequently than monthly, 

or, for a unit with a maximum rated heat 

input capacity less than 100 mmBtu/hr 

(or a group of such units) regardless of 

the molecular weight sampling 

frequency, the annual average molecular 

weight for Equation C–5 shall either be 

computed according to paragraph 

(a)(3)(iii)(A)(3) of this section or as the 

arithmetic average molecular weight for 

all values for the year (including valid 

samples and substitute data values 

under § 98.35). 

* * * * * 

(b) * * * 

(1) * * * 

(vii) May be used for the combustion 

of MSW and/or tires in a unit, provided 

that no more than 10 percent of the 

unit’s annual heat input is derived from 

those fuels, combined. 

* * * * * 

(c) * * * 

(1) * * * 

EF = Fuel-specific default emission factor for 

CH4 or N2O, from Table C–2 of this 

subpart (kg CH4 or N2O per mmBtu), 

except for natural gas compressor drivers 

at facilities subject to subpart W of this 

part, which must use the applicable CH4

emission factor from Table W–9 to 

subpart W of this part. 

* * * * * 

(i) * * * 

EF = Fuel-specific default emission factor for 

CH4 or N2O, from Table C–2 of this 

subpart (kg CH4 or N2O per mmBtu), 

except for natural gas compressor drivers 

at facilities subject to subpart W of this 

part, which must use the applicable CH4

emission factor from Table W–9 to 

subpart W of this part. 

* * * * * 

(ii) * * * 

EF = Fuel-specific default emission factor for 

CH4 or N2O, from Table C–2 of this 

subpart (kg CH4 or N2O per mmBtu), 

except for natural gas compressor drivers 

at facilities subject to subpart W of this 

part, which must use the applicable CH4

emission factor from Table W–9 to 

subpart W of this part. 

* * * * * 

(2) * * * 

EF = Fuel-specific default emission factor for 

CH4 or N2O, from Table C–2 of this 

subpart (kg CH4 or N2O per mmBtu), 

except for natural gas compressor drivers 

at facilities subject to subpart W of this 

part, which must use the applicable CH4

emission factor from Table W–9 to 

subpart W of this part. 

* * * * * 

(3) * * * 

EF = Fuel-specific emission factor for CH4 or 

N2O, from Table C–2 of this subpart (kg 

CH4 or N2O per mmBtu), except for 

natural gas compressor drivers at 

facilities subject to subpart W of this 

part, which must use the applicable CH4

emission factor from Table W–9 to 

subpart W of this part. 

* * * * * 

(4) * * * 

EF = Fuel-specific emission factor for CH4 or 

N2O, from Table C–2 of this subpart (kg 

CH4 or N2O per mmBtu), except for 

natural gas compressor drivers at 

facilities subject to subpart W of this 

part, which must use the applicable CH4

emission factor from Table W–9 to 

subpart W of this part. 

* * * * * 

(6) * * * 

(i) If the mass, volume, or heat input 

of each component fuel in the blend is 

determined before the fuels are mixed 

and combusted, calculate and report 

CH4 and N2O emissions separately for 

each component fuel, using the 

applicable procedures in this paragraph 

(c). 

(ii) If the mass, volume, or heat input 

of each component fuel in the blend is 

not determined before the fuels are 

mixed and combusted, a reasonable 

estimate of the percentage composition 

of the blend, based on best available 

information, is required. Perform the 

following calculations for each 

component fuel ‘‘i’’ that is listed in 

Table C–2: 

(A) Multiply (% Fuel)i, the estimated 

mass, volume, or heat input percentage 

of component fuel ‘‘i’’ (expressed as a 

decimal fraction), by the total annual 

mass, volume, or heat input of the 

blended fuel combusted during the 

reporting year, to obtain an estimate of 

the annual value for component ‘‘i’’; 

* * * * * 

(C) Calculate the annual CH4 and N2O 

emissions from component ‘‘i’’, using 

Equation C–8 (fuel mass or volume), C– 

8a (fuel heat input), C–8b (fuel heat 

input), C–9a (fuel mass or volume), or 

C–10 (fuel heat input) of this section, as 

applicable; 

* * * * * 

(d) * * * 

(1) * * * 

R = The number of moles of CO2 released per 

mole of sorbent used (R = 1.00 when the 

sorbent is CaCO3 and the targeted acid 

gas species is SO2). 

* * * * * 

(e) Biogenic CO2 emissions from 

combustion of biomass with other fuels. 

Use the applicable procedures of this 

paragraph (e) to estimate biogenic CO2

emissions from units that combust a 

combination of biomass and fossil fuels 

(i.e., either co-fired or blended fuels). 

Separate reporting of biogenic CO2

emissions from the combined 

combustion of biomass and fossil fuels 

is required for those biomass fuels listed 

in Table C–1 of this section, MSW, and 

tires. In addition, when a biomass fuel 

that is not listed in Table C–1 is 

combusted in a unit that has a 

maximum rated heat input greater than 

250 mmBtu/hr, if the biomass fuel 

accounts for 10% or more of the annual 

heat input to the unit, and if the unit 

does not use CEMS to quantify its 

annual CO2 mass emissions, then, 

pursuant to § 98.33(b)(3)(iii), Tier 3 

must be used to determine the carbon 

content of the biomass fuel and to 

calculate the biogenic CO2 emissions 

from combustion of the fuel. 

Notwithstanding these requirements, in 

accordance with § 98.3(c)(12), separate 

reporting of biogenic CO2 emissions is 

optional for the 2010 reporting year for 

units subject to subpart D of this part 

and for units that use the CO2 mass 

emissions calculation methodologies in 

part 75 of this chapter, pursuant to 

paragraph (a)(5) of this section. 

However, if the owner or operator opts 

to report biogenic CO2 emissions 

separately for these units, the 

appropriate method(s) in this paragraph 

(e) shall be used. 

(1) You may use Equation C–1 of this 

subpart to calculate the annual CO2

mass emissions from the combustion of 

the biomass fuels listed in Table C–1 of 

this subpart, in a unit of any size, 

including units equipped with a CO2

CEMS, except when the use of Tier 2 is 

required as specified in paragraph 

(b)(1)(iv) of this section. Determine the 

quantity of biomass combusted using 

one of the following procedures in this 

paragraph (e)(1), as appropriate, and 

document the selected procedures in the 

Monitoring Plan under § 98.3(g): 

* * * * * 

(2) * * * 

(v) Calculate the biogenic percentage 

of the annual CO2 emissions expressed 

as a decimal fraction, using Equation C– 

14 of this section: 

* * * * * 

(3) You must use the procedures in 

paragraphs (e)(3)(i) through (iii) of this 

section to determine the annual 

biogenic CO2 emissions from the 


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combustion of MSW, except as 

otherwise provided in paragraph 

(e)(3)(iv) of this section. These 

procedures also may be used for any 

unit that co-fires biomass and fossil 

fuels, including units equipped with a 

CO2 CEMS. 

* * * * * 

(iv) In lieu of following the 

procedures in paragraphs (e)(3)(i) 

through (iii) of this section, the 

procedures of this paragraph may be 

used for the combustion of tires 

regardless of the percent of the annual 

heat input provided by tires. The 

calculation procedure in this paragraph 

may be used for the combustion of MSW 

if the combustion of MSW provides no 

more than 10 percent of the annual heat 

input to the unit or if a small, batch 

incinerator combusts no more than 

1,000 tons per year of MSW. 

(A) Calculate the total annual CO2

emissions from combustion of MSW 

and/or tires in the unit, using the 

applicable methodology in paragraphs 

(a)(1) through (3) of this section for units 

using Tier 1, Tier 2, or Tier 3; otherwise 

use the Tier 1 calculation methodology 

in paragraph (a)(1) of this section for 

units using either the Tier 4 or 

Alternative Part 75 calculation 

methodologies to calculate total CO2

emissions. 

(B) Multiply the result from paragraph 

(e)(3)(iv)(A) of this section by the 

appropriate default factor to determine 

the annual biogenic CO2 emissions, in 

metric tons. For MSW, use a default 

factor of 0.60 and for tires, use a default 

factor of 0.24. 

* * * * * 

■ 14. Amend § 98.34 by revising 

paragraphs (c)(6) and (d) to read as 

follows: 

§ 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 

§ 98.33(e)(3)(iv), when municipal solid 

waste (MSW) is either the primary fuel 

combusted in a unit or the only fuel 

with a biogenic component combusted 

in the unit, determine the biogenic 

portion of the CO2 emissions using 

ASTM D6866–16 Standard Test 

Methods for Determining the Biobased 

Content of Solid, Liquid, and Gaseous 

Samples Using Radiocarbon Analysis) 

and ASTM D7459–08 Standard Practice 

for Collection of Integrated Samples for 

the Speciation of Biomass (Biogenic) 

and Fossil-Derived Carbon Dioxide 

Emitted from Stationary Emissions 

Sources (both incorporated by reference, 

see § 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. 

* * * * * 

■ 15. Amend § 98.36 by: 

■ a. Revising paragraphs (c)(1) 

introductory text, (c)(1)(ii) and (vi), 

(c)(3) introductory text, and (c)(3)(vi); 

■ b. Adding paragraph (c)(3)(xi); and 

■ c. Revising paragraphs (e)(2)(ii)(C) and 

(e)(2)(xi). 

The revisions and addition read as 

follows: 

§ 98.36 Data reporting requirements. 

* * * * * 

(c) * * * 

(1) Aggregation of units. If a facility 

contains two or more units (e.g., boilers 

or combustion turbines), each of which 

has a maximum rated heat input 

capacity of 250 mmBtu/hr or less, you 

may report the combined GHG 

emissions for the group of units in lieu 

of reporting GHG emissions from the 

individual units, provided that the use 

of Tier 4 is not required or elected for 

any of the units and the units use the 

same tier for any common fuels 

combusted. Compressor drivers that 

calculate emissions using an applicable 

CH4 emission factor from Table W–9 to 

subpart W of this part, must be reported 

as their own aggregation of units 

configuration, according to design class 

(i.e., two-stroke lean-burn, four-stroke 

lean-burn, and four-stroke rich-burn). 

You may not have a combination of one 

design class of compressor driver (using 

one Table W–9 CH4 emission factor) and 

other combustion units (e.g., using a 

Table C–2 CH4 emission factor or 

another Table W–9 CH4 emission factor) 

in the same aggregation of units 

configuration. If this option is selected, 

the following information shall be 

reported instead of the information in 

paragraph (b) of this section: 

* * * * * 

(ii) For each unit in the group greater 

than or equal to 10 mmBtu/hr, the unit 

type, maximum rated heat input 

capacity, and an estimate of the total 

annual heat input (expressed as a 

decimal fraction). To determine the total 

annual heat input decimal fraction for a 

unit, divide the actual heat input for 

that unit (all fuels) by the sum of the 

actual heat input for all units (all fuels), 

including units less than 10 mmBtu/hr. 

Estimates of the actual heat inputs may 

be based on company records. If all 

units in this configuration are less than 

10 (mmBtu/hr), this requirement does 

not apply. 

* * * * * 

(vi) Annual CO2 mass emissions and 

annual CH4, and N2O mass emissions, 

aggregated for each type of fuel 

combusted in the group of units during 

the report year, expressed in metric tons 

of each gas and in metric tons of CO2e. 

If any of the units burn biomass, report 

also the annual CO2 emissions from 

combustion of all biomass fuels 

combined, expressed in metric tons. 

* * * * * 


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(3) Common pipe configurations. 

When two or more stationary 

combustion units at a facility combust 

the same type of liquid or gaseous fuel 

and the fuel is fed to the individual 

units through a common supply line or 

pipe, you may report the combined 

emissions from the units served by the 

common supply line, in lieu of 

separately reporting the GHG emissions 

from the individual units, provided that 

the total amount of fuel combusted by 

the units is accurately measured at the 

common pipe or supply line using a fuel 

flow meter, or, for natural gas, the 

amount of fuel combusted may be 

obtained from gas billing records. For 

Tier 3 applications, the flow meter shall 

be calibrated in accordance with 

§ 98.34(b). If a portion of the fuel 

measured (or obtained from gas billing 

records) at the main supply line is 

diverted to either: A flare; or another 

stationary fuel combustion unit (or 

units), including units that use a CO2

mass emissions calculation method in 

part 75 of this chapter; or a chemical or 

industrial process (where it is used as a 

raw material but not combusted), and 

the remainder of the fuel is distributed 

to a group of combustion units for 

which you elect to use the common pipe 

reporting option, you may use company 

records to subtract out the diverted 

portion of the fuel from the fuel 

measured (or obtained from gas billing 

records) at the main supply line prior to 

performing the GHG emissions 

calculations for the group of units using 

the common pipe option. If the diverted 

portion of the fuel is combusted, the 

GHG emissions from the diverted 

portion shall be accounted for in 

accordance with the applicable 

provisions of this part. When the 

common pipe option is selected, the 

applicable tier shall be used based on 

the maximum rated heat input capacity 

of the largest unit served by the 

common pipe configuration, except 

where the applicable tier is based on 

criteria other than unit size. For 

example, if the maximum rated heat 

input capacity of the largest unit is 

greater than 250 mmBtu/hr, Tier 3 will 

apply, unless the fuel transported 

through the common pipe is natural gas 

or distillate oil, in which case Tier 2 

may be used, in accordance with 

§ 98.33(b)(2)(ii). As a second example, 

in accordance with § 98.33(b)(1)(v), Tier 

1 may be used regardless of unit size 

when natural gas is transported through 

the common pipe, if the annual fuel 

consumption is obtained from gas 

billing records in units of therms or 

mmBtu. Compressor drivers that 

calculate emissions using an applicable 

CH4 emission factor from Table W–9 to 

subpart W of this part, must be reported 

as their own common pipe 

configuration, according to design class 

(i.e., two-stroke lean-burn, four-stroke 

lean-burn, and four-stroke rich-burn). 

You may not have a combination of one 

design class of compressor driver (using 

one Table W–9 CH4 emission factor) and 

other combustion units (e.g., using a 

Table C–2 CH4 emission factor or 

another Table W–9 CH4 emission factor) 

in the same common pipe configuration. 

When the common pipe reporting 

option is selected, the following 

information shall be reported instead of 

the information in paragraph (b) of this 

section: 

* * * * * 

(vi) If any of the units burns biomass, 

the annual CO2 emissions from 

combustion of all biomass fuels from the 

units served by the common pipe, 

expressed in metric tons. 

* * * * * 

(xi) For each unit in the group greater 

than or equal to 10 mmBtu/hr, the unit 

type, maximum rated heat input 

capacity, and an estimate of the total 

annual heat input (expressed as a 

decimal fraction). To determine the total 

annual heat input decimal fraction for a 

unit, divide the actual heat input for 

that unit (all fuels) by the sum of the 

actual heat input for all units (all fuels), 

including units less than 10 mmBtu/hr. 

Estimated heat input values may be 

based on company records. If all units 

in this configuration are less than 10 

(mmBtu/hr), this requirement does not 

apply. 

* * * * * 

(e) * * * 

(2) * * * 

(ii) * * * 

(C) The annual average, and, where 

applicable, monthly high heat values 

used in the CO2 emissions calculations 

for each type of fuel combusted during 

the reporting year, in mmBtu per short 

ton for solid fuels, mmBtu per gallon for 

liquid fuels, and mmBtu per scf for 

gaseous fuels. Report an HHV value for 

each calendar month in which HHV 

determination is required. If multiple 

values are obtained in a given month, 

report the arithmetic average value for 

the month. 

* * * * * 

(xi) When ASTM methods D7459–08 

and D6866–16 (both incorporated by 

reference, see § 98.7) are used in 

accordance with § 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). 

* * * * * 

■ 16. Amend § 98.37 by revising 

paragraphs (b) introductory text, (b)(9) 

through (11), (14), (18), (20), (22), and 

(23) to read as follows: 

§ 98.37 Records that must be retained. 

* * * * * 

(b) For each stationary fuel 

combustion source that elects to use the 

verification software specified in 

§ 98.5(b) rather than report data 

specified in paragraphs (b)(9)(iii), 

(c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), 

(e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iv)(A), 

(e)(2)(iv)(C), (e)(2)(iv)(F), and 

(e)(2)(ix)(D) through (F) of this section, 

you must keep a record of the file 

generated by the verification software 

for the applicable data specified in 

paragraphs (b)(1) through (37) of this 

section. Retention of this file satisfies 

the recordkeeping requirement for the 

data in paragraphs (b)(1) through (37) of 

this section. 

* * * * * 

(9) Measured high heat value of each 

solid fuel, for month (which may be the 

arithmetic average of multiple 

determinations), or, if applicable, an 

appropriate substitute data value 

(mmBtu per ton) (Equation C–2b of 

§ 98.33). Annual average HHV of each 

solid fuel (mmBtu per ton) (Equation C– 

2a of § 98.33). 

(10) Measured high heat value of each 

liquid fuel, for month (which may be 

the arithmetic average of multiple 

determinations), or, if applicable, an 

appropriate substitute data value 

(mmBtu per gallons) (Equation C–2b). 

Annual average HHV of each liquid fuel 

(mmBtu per gallons) (Equation C–2a of 

§ 98.33). 

(11) Measured high heat value of each 

gaseous fuel, for month (which may be 

the arithmetic average of multiple 

determinations), or, if applicable, an 

appropriate substitute data value 

(mmBtu per scf) (Equation C–2b). 

Annual average HHV of each gaseous 

fuel (mmBtu per scf) (Equation C–2a of 

§ 98.33). 

* * * * * 

(14) Volume of each gaseous fuel 

combusted during month (scf) (Equation 

C–2b, Equation C–5a, Equation C–5b). 

* * * * * 

(18) Annual average carbon content of 

each solid fuel (percent by weight, 

expressed as a decimal fraction) 

(Equation C–3). Where applicable, 

monthly carbon content of each solid 

fuel (which may be the arithmetic 


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37044 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

1Reporters subject to subpart W of this part may 

only use the default CH4 emission factor for natural 

gas-fired combustion units that are not compressor 

drivers. For natural gas-fired compressor drivers at 

facilities subject to subpart W of this part, reporters 

must use the applicable CH4 emission factor from 

Table W–9 to subpart W of this part. 

average of multiple determinations), or, 

if applicable, an appropriate substitute 

data value (percent by weight, expressed 

as a decimal fraction) (Equation C–2b— 

see the definition of ‘‘CC’’ in Equation 

C–3). 

* * * * * 

(20) Annual average carbon content of 

each liquid fuel (kg C per gallon of fuel) 

(Equation C–4). Where applicable, 

monthly carbon content of each liquid 

fuel (which may be the arithmetic 

average of multiple determinations), or, 

if applicable, an appropriate substitute 

data value (kg C per gallon of fuel) 

(Equation C–2b—see the definition of 

‘‘CC’’ in Equation C–3). 

* * * * * 

(22) Annual average carbon content of 

each gaseous fuel (kg C per kg of fuel) 

(Equation C–5). Where applicable, 

monthly carbon content of each gaseous 

(which may be the arithmetic average of 

multiple determinations), or, if 

applicable, an appropriate substitute 

data value (kg C per kg of fuel) 

(Equation C–5a). 

(23) Annual average molecular weight 

of each gaseous fuel (kg/kg-mole) 

(Equation C–5). Where applicable, 

monthly molecular weight of each 

gaseous (which may be the arithmetic 

average of multiple determinations), or, 

if applicable, an appropriate substitute 

data value (kg/kg-mole) (Equation C– 

5b). 

* * * * * 

■ 17. Amend table C–2 to subpart C of 

part 98 by revising the entry ‘‘Natural 

Gas’’ to read as follows: 

TABLE C–2 TO SUBPART C OF PART 98—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL

Fuel type Default CH4 emission factor 

(kg CH4/mmBtu) 

Default N2O emission factor 

(kg N2O/mmBtu) 

*******

Natural Gas 1 .................................. 1.0 × 10¥03 ................................................................ 1.0 × 10¥04

* * * * * * * 

* * * * * 

Subpart G—Ammonia Manufacturing 

■ 18. Amend § 98.72 by revising 

paragraph (a) to read as follows: 

§ 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. 

* * * * * 

■ 19. Amend § 98.73 by revising the 

introductory text and paragraph (b) to 

read as follows: 

§ 98.73 Calculating GHG emissions 

You must calculate and report the 

annual net CO2 process emissions from 

each ammonia manufacturing unit using 

the procedures in either paragraph (a) or 

(b) of this section. 

* * * * * 

(b) Calculate and report under this 

subpart process CO2 emissions using the 

procedures in paragraphs (b)(1) through 

(4) of this section, as applicable. 

(1) Gaseous feedstock. You must 

calculate, from each ammonia 

manufacturing unit, the CO2 process 

emissions from gaseous feedstock 

according to Equation G–1 of this 

section: 

Where: 

CO2,G = Annual CO2 emissions arising from 

gaseous feedstock consumption (metric 

tons). 

Fdstkn = Volume of the gaseous feedstock 

used in month n (scf of feedstock). 

CCn = Carbon content of the gaseous 

feedstock, for month n (kg C per kg of 

feedstock), determined according to 

98.74(c). 

MW = Molecular weight of the gaseous 

feedstock (kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at standard 

conditions). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

n = Number of month. 

(2) Liquid feedstock. You must 

calculate, from each ammonia 

manufacturing unit, the CO2 process 

emissions from liquid feedstock 

according to Equation G–2 of this 

section: 

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). 


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CCn = Carbon content of the liquid feedstock, 

for month n (kg C per gallon of 

feedstock) determined according to 

98.74(c). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

n = Number of month. 

(3) Solid feedstock. You must 

calculate, from each ammonia 

manufacturing unit, the CO2 process 

emissions from solid feedstock 

according to Equation G–3 of this 

section: 

Where: 

CO2,S = Annual CO2 emissions arising from 

solid feedstock consumption (metric 

tons). 

Fdstkn = Mass of the solid feedstock used in 

month n (kg of feedstock). 

CCn = Carbon content of the solid feedstock, 

for month n (kg C per kg of feedstock), 

determined according to 98.74(c). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

n = Number of month. 

(4) Net CO2 process emissions. You 

must calculate the annual net CO2

process emissions at each ammonia 

manufacturing unit according to 

Equation G–4 of this section: 

Where: 

CO2,net = Annual net CO2 process emissions 

from each ammonia manufacturing unit 

(metric tons). 

CO2,p = Annual CO2 process emissions 

arising from feedstock consumption 

based on feedstock type ‘‘p’’ (metric 

tons/yr) as calculated in paragraphs 

(b)(1) through (3) of this section. 

P = Index for feedstock type; 1 indicates 

gaseous feedstock; 2 indicates liquid 

feedstock; and 3 indicates solid 

feedstock. 

CO2,urea,n = Amount of carbon dioxide 

collected from ammonia production and 

consumed on site for urea production, in 

month n (metric tons). 

MeOHn = Mass of methanol intentionally 

produced as a desired product for month 

n (metric tons). 

44/32 = Ratio of molecular weights, CO2 to 

methanol. 

* * * * * 

■ 20. Amend § 98.76 by revising the 

introductory text and paragraphs (b)(1) 

and (13) to read as follows: 

§ 98.76 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a) and (b) of this section, 

as applicable for each ammonia 

manufacturing unit. 

* * * * * 

(b) * * * 

(1) Annual net CO2 process emissions 

(metric tons) for each ammonia 

manufacturing unit. 

* * * * * 

(13) Annual amount of CO2 collected 

from ammonia production (metric tons) 

and consumed on site for urea 

production and the method used to 

determine the CO2 consumed in urea 

production. 

* * * * * 

■ 21. Amend § 98.77 by revising 

paragraph (c) introductory text and 

adding paragraphs (c)(8) and (9) to read 

as follows: 

§ 98.77 Records that must be retained. 

* * * * * 

(c) You must keep a record of the file 

generated by the verification software 

specified in § 98.5(b) for the applicable 

data specified in paragraphs (c)(1) 

through (9) of this section. Retention of 

this file satisfies the recordkeeping 

requirement for the data in paragraphs 

(c)(1) through (9) of this section. 

* * * * * 

(8) Quantity of CO2 collected from 

ammonia production and consumed on 

site for urea production in month 

(Equation G–4 of § 98.73). 

(9) Quantity of methanol intentionally 

produced as a desired product in month 

(metric tons) (Equation G–4). 

Subpart H—Cement Production 

■ 22. Amend § 98.83 by: 

■ a. Revising paragraph (d)(1); 

■ b. Revising parameters ‘‘CKDCaO,’’ 

‘‘CKDCaO,’’ ‘‘CKDMgO,’’ and ‘‘CKDMgO’’ of 

Equation H–4 in paragraph (d)(2)(ii)(A); 

and 

■ c. Revising paragraph (d)(3). 

The revisions read as follows: 

§ 98.83 Calculating GHG emissions. 

* * * * * 

(d) * * * 

(1) Calculate CO2 process emissions 

from all kilns at the facility using 

Equation H–1 of this section: 

Where: 

CO2 CMF = Annual process emissions of CO2

from cement manufacturing, metric tons. 

CO2 Cli,m = Total annual emissions of CO2

from clinker production from kiln m, 

metric tons. 

CO2 rm,m = Total annual emissions of CO2

from raw materials from kiln m, metric 

tons. 

K = Total number of kilns at a cement 

manufacturing facility. 

(2) * * * 

(ii) * * * 

(A) * * * 

CKDCaO = Quarterly total CaO content of CKD 

not recycled to the kiln, wt-fraction. 

CKDncCaO = Quarterly non-calcined CaO 

content of CKD not recycled to the kiln, 

wt-fraction. 

* * * * * 

CKDMgO = Quarterly total MgO content of 

CKD not recycled to the kiln, wt-fraction. 

CKDncMgO = Quarterly non-calcined MgO 

content of CKD not recycled to the kiln, 

wt-fraction. 

* * * * * 

(3) CO2 emissions from raw materials 

from each kiln. Calculate CO2 emissions 

from raw materials using Equation H–5 

of this section: 


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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 

§ 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. 

* * * * * 

■ 23. Amend § 98.86 by adding 

paragraphs (a)(4) through (13) and 

(b)(19) through (28) to read as follows: 

§ 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 noncalcined 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 noncalcined MgO content of clinker at the 

facility, wt-fraction. 

(8) Annual arithmetic average of total 

CaO content of CKD not recycled to the 

kiln(s) at the facility, wt-fraction. 

(9) Annual arithmetic average of noncalcined CaO content of CKD not 

recycled to the kiln(s) at the facility, wtfraction. 

(10) Annual arithmetic average of 

total MgO content of CKD not recycled 

to the kiln(s) at the facility, wt-fraction. 

(11) Annual arithmetic average of 

non-calcined MgO content not recycled 

to the kiln(s) at the facility, wt-fraction. 

(12) Annual facility CKD not recycled 

to the kiln(s), tons. 

(13) The amount of raw kiln feed 

consumed annually at the facility, tons 

(dry basis). 

(b) * * * 

(19) Annual arithmetic average of 

total CaO content of clinker at the 

facility, wt-fraction. 

(20) Annual arithmetic average of 

non-calcined CaO content of clinker at 

the facility, wt-fraction. 

(21) Annual arithmetic average of 

total MgO content of clinker at the 

facility, wt-fraction. 

(22) Annual arithmetic average of 

non-calcined MgO content of clinker at 

the facility, wt-fraction. 

(23) Annual arithmetic average of 

total CaO content of CKD not recycled 

to the kiln(s) at the facility, wt-fraction. 

(24) Annual arithmetic average of 

non-calcined CaO content of CKD not 

recycled to the kiln(s) at the facility, wtfraction. 

(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, wtfraction. 

(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 

■ 24. Amend § 98.91 by revising 

paragraphs (a) introductory text and 

(a)(1) through (3), and parameters ‘‘Ei’’ 

and ‘‘i’’ of Equation I–4 in paragraph 

(a)(4) to read as follows: 

§ 98.91 Reporting threshold. 

(a) You must report GHG emissions 

under this subpart if electronics 

manufacturing production processes, as 

defined in § 98.90, are performed at 

your facility and your facility meets the 

requirements of either § 98.2(a)(1) or 

(a)(2). To calculate total annual GHG 

emissions for comparison to the 25,000 

metric ton CO2e per year emission 

threshold in § 98.2(a)(2), follow the 

requirements of § 98.2(b), with one 

exception. Rather than using the 

calculation methodologies in § 98.93 to 

calculate emissions from electronics 

manufacturing production processes, 

calculate emissions of each fluorinated 

GHG from electronics manufacturing 

production processes by using 

paragraph (a)(1), (2), or (3) of this 

section, as appropriate, and then sum 

the emissions of each fluorinated GHG 

and account for fluorinated heat transfer 

fluid emissions by using paragraph 

(a)(4) of this section. 

(1) If you manufacture 

semiconductors or MEMS you must 

calculate annual production process 

emissions resulting from the use of each 

input gas for threshold applicability 

purposes using either the default 

emission factors shown in Table I–1 to 

this subpart and Equation I–1A of this 

subpart, or the consumption of each 

input gas, the default emission factors 

shown in Table I–2 to this subpart, and 

Equation I–1B of this subpart. 

Where: 

Ei = Annual production process emissions of 

gas i for threshold applicability purposes 

(metric tons CO2e). 

S = 100 percent of annual manufacturing 

capacity of a facility as calculated using 

Equation I–5 of this subpart (m2). 

EFi = Emission factor for gas i (kg/m2) 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. 

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 

§ 98.90(a)(1) through (a)(4) must be 

considered for threshold applicability 

purposes. 

(1–Ui), BCF4, and BC2F6 = Default emission 

factors for the gas consumption-based 


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threshold applicability determination 

listed in Table I–2 to this subpart. 

GWPi = Gas-appropriate GWP as provided in 

Table A–1 to subpart A of this part. 

0.001 = Conversion factor from kg to metric 

tons. 

i = Input gas. 

(2) If you manufacture LCDs, you 

must calculate annual production 

process emissions resulting from the use 

of each input gas for threshold 

applicability purposes using either the 

default emission factors shown in Table 

I–1 to this subpart and Equation I–2 of 

this subpart or the consumption of each 

input gas, the default emission factors 

shown in Table I–2 to this subpart, and 

Equation I–1B of this subpart. 

Where: 

Ei = Annual production process emissions of 

gas i for threshold applicability purposes 

(metric tons CO2e). 

S = 100 percent of annual manufacturing 

capacity of a facility as calculated using 

Equation I–5 of this subpart (m2). 

EFi = Emission factor for gas i (g/m2). 

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. 

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 § 98.90(a)(1) through (a)(4) must 

be considered for threshold applicability 

purposes. 

(1–Ui), BCF4, and BC2F6 = Default emission 

factors for the gas consumption-based 

threshold applicability determination 

listed in Table I–2 to this subpart. 

GWPi = Gas-appropriate GWP as provided in 

Table A–1 to subpart A of this part. 

0.001 = Conversion factor from kg to metric 

tons. 

i = Input gas. 

(3) If you manufacture PVs, you must 

calculate annual production process 

emissions resulting from the use of each 

input gas i for threshold applicability 

purposes using gas-appropriate GWP 

values shown in Table A–1 to subpart 

A of this part, the default emission 

factors shown in Table I–2 to this 

subpart, and Equation I–3 of this 

subpart. 

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 § 98.90(a)(1) through 

(a)(4) must be considered for threshold 

applicability purposes. 

(1–Ui), BCF4, and BC2F6 = Default emission 

factors for the gas consumption-based 

threshold applicability determination 

listed in Table I–2 to this subpart. 

GWPi = Gas-appropriate GWP as provided in 

Table A–1 to subpart A of this part. 

0.001 = Conversion factor from kg to metric 

tons. 

i = Input gas. 

(4) * * * 

Ei = Annual production process emissions of 

gas i for threshold applicability purposes 

(metric tons CO2e), as calculated in 

Equations I–1a, I–1b, I–2a, I–2b, or I–3 of 

this subpart. 

i = Emitted gas. 

* * * * * 

■ 25. Amend § 98.92 by revising 

paragraph (a) to read as follows: 

§ 98.92 GHGs to report. 

(a) You must report emissions of 

fluorinated GHGs (as defined in § 98.6), 

N2O, and fluorinated heat transfer fluids 

(as defined in § 98.98). The fluorinated 

GHGs and fluorinated heat transfer 

fluids that are emitted from electronics 

manufacturing production processes 

include, but are not limited to, those 

listed in Table I–21 to this subpart. You 

must individually report, as 

appropriate: 

* * * * * 

■ 26. Amend § 98.93 by: 

■ a. Revising paragraph (a)(1) 

introductory text; 

■ b. Revising parameters ‘‘Eij’’ and ‘‘N’’ 

of Equation I–6 in paragraph (a)(1) 

introductory text; 

■ c. Revising Equation I–7 in paragraph 

(a)(1) introductory text; 

■ d. Revising parameters ‘‘BEijk’’ and 

‘‘N’’ of Equation I–7 in paragraph (a)(1) 

introductory text; 

■ e. Revising paragraphs (a)(1)(i) and (ii) 

and (a)(2) and (6); 

■ f. Adding paragraph (a)(7); 

■ g. Revising the introductory text of 

paragraphs (e) and (i); 

■ h. Removing and reserving paragraphs 

(i)(1) and (2); 

■ i. Revising paragraph (i)(3) 

introductory text and (i)(3)(i), (iii) 

through (vi), and (viii)). 

■ j. Adding paragraph (i)(3)(ix); 

■ k. Revising paragraph (i)(4); and 

■ l. Removing paragraph (i)(5). 

The revisions and additions read as 

follows: 

§ 98.93 Calculating GHG emissions. 

(a) * * * 

(1) If you manufacture 

semiconductors, you must adhere to the 

procedures in paragraphs (a)(1)(i) 

through (iii) of this section. You must 

calculate annual emissions of each 

input gas and of each by-product gas 

using Equations I–6, I–7, and I–9 of this 

subpart. If your fab uses less than 50 kg 

of a fluorinated GHG in one reporting 

year, you may calculate emissions as 

equal to your fab’s annual consumption 

for that specific gas as calculated in 

Equation I–11 of this subpart, plus any 

by-product emissions of that gas 

calculated under paragraph (a) of this 

section. 

* * * * * 

Eij = Annual emissions of input gas i from 

process sub-type or process type j as 

calculated in Equation I–8A of this 

subpart (metric tons). 

N = The total number of process sub-types j 

that depends on the electronics 

manufacturing fab and emission 

calculation methodology. If Eij is 

calculated for a process type j in 

Equation I–8A of this subpart, N = 1. 

* * * * * 


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* * * * * 

BEkij = Annual emissions of by-product gas 

k formed from input gas i used for 

process sub-type or process type j as 

calculated in Equation I–8B of this 

subpart (metric tons). 

N = The total number of process sub-types j 

that depends on the electronics 

manufacturing fab and emission 

calculation methodology. If BEkij is 

calculated for a process type j in 

Equation I–8B of this subpart, N = 1. 

* * * * * 

(i) You must calculate annual fablevel emissions of each fluorinated GHG 

used for the plasma etching/wafer 

cleaning process type using default 

utilization and by-product formation 

rates as shown in Table I–3 or I–4 of this 

subpart, and by using Equations I–8A 

and I–8B of this subpart. 

Where: 

Eij = Annual emissions of input gas i from 

process sub-type or process type j, on a 

fab basis (metric tons). 

Cij = Amount of input gas i consumed for 

process sub-type or process type j, as 

calculated in Equation I–13 of this 

subpart, on a fab basis (kg). 

Uij = Process utilization rate for input gas i 

for process sub-type or process type j 

(expressed as a decimal fraction). 

Aij = Fraction of input gas i used in process 

sub-type or process type j with 

abatement systems, on a fab basis 

(expressed as a decimal fraction). 

Dij = Fraction of input gas i destroyed or 

removed when fed into abatement 

systems by process tools where process 

sub-type, or process type j is used, on a 

fab basis, calculated by taking the tool 

weighted average of the claimed DREs 

for input gas on i on tools that use 

process type or process sub-type j 

(expressed as a decimal fraction). This is 

zero unless the facility adheres to the 

requirements in § 98.94(f). 

UTij = The average uptime factor of all 

abatement systems connected to process 

tools in the fab using input gas i in 

process sub-type or process type j, as 

calculated in Equation I–15 of this 

subpart, on a fab basis (expressed as a 

decimal fraction). 

0.001 = Conversion factor from kg to metric 

tons. 

i = Input gas. 

j = Process sub-type or process type. 

Where: 

BEkij = Annual emissions of by-product gas 

k formed from input gas I from process 

sub-type or process type j, on a fab basis 

(metric tons). 

Bijk = By-product formation rate of gas k 

created as a by-product per amount of 

input gas i (kg) consumed by process 

sub-type or process type j (kg). For noncarbon containing input gases used in 

chamber cleaning process sub-types, this 

is zero when the combination of input 

gas and chamber cleaning process subtype is never used to clean chamber 

walls on equipment that process carboncontaining films during the year (e.g., 

when NF3 is used in remote plasma 

cleaning processes to only clean 

chambers that never process carboncontaining films during the year). 

Cij = Amount of input gas i consumed for 

process sub-type, or process type j, as 

calculated in Equation I–13 of this 

subpart, on a fab basis (kg). 

akij = Fraction of input gas I used for process 

sub-type, or process type j with 

abatement systems, on a fab basis 

(expressed as a decimal fraction). 

Dkij = Fraction of by-product gas k destroyed 

or removed in when fed into abatement 

systems by process tools where process 

sub-type or process type j is used, on a 

fab basis, calculated by taking the tool 

weighted average of the claimed DREs 

for by-product gas k on tools that use 

input gas i in process type or process 

sub-type j (expressed as a decimal 

fraction). This is zero unless the facility 

adheres to the requirements in § 98.94(f). 

UTkij = The average uptime factor of all 

abatement systems connected to process 

tools in the fab emitting by-product gas 

k, formed from input gas I in process 

sub-type or process type j, on a fab basis 

(expressed as a decimal fraction). For 

this equation, UTkij is assumed to be 

equal to UTij as calculated in Equation I– 

15 of this subpart. 

0.001 = Conversion factor from kg to metric 

tons. 

i = Input gas. 

j = Process sub-type or process type. 

k = By-product gas. 

(ii) You must calculate annual fablevel 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 byproduct formation rates as shown in 

Table I–3 or I–4 of this subpart, and by 

using Equations I–8A and I–8B of this 

subpart. 

* * * * * 

(2) If you manufacture MEMS or PVs 

and use semiconductor tools and 

processes, you may use § 98.3(a)(1) to 

calculate annual fab-level emissions for 

those processes. For all other tools and 

processes used to manufacture MEMs, 

LCD and PV, you must calculate annual 

fab-level emissions of each fluorinated 

GHG used for the plasma etching and 

chamber cleaning process types using 

default utilization and by-product 

formation rates as shown in Table I–5, 

I–6, or I–7 of this subpart, as 

appropriate, and by using Equations I– 

8A and I–8B of this subpart. If default 

values are not available for a particular 

input gas and process type or sub-type 

combination in Tables I–5, I–6, or I–7, 

you must follow the procedures in 

paragraph (a)(6) of this section. If your 

fab uses less than 50 kg of a fluorinated 

GHG in one reporting year, you may 

calculate emissions as equal to your 

fab’s annual consumption for that 

specific gas as calculated in Equation I– 

11 of this subpart, plus any by-product 

emissions of that gas calculated under 

this paragraph (a). 

* * * * * 

(6) If you are required, or elect, to 

perform calculations using default 

emission factors for gas utilization and 

by-product formation rates according to 

the procedures in paragraph (a)(1) or 

(a)(2) of this section, and default values 

are not available for a particular input 

gas and process type or sub-type 

combination in Tables I–3, I–4, I–5, I– 

6, or I–7, you must use a utilization rate 

(Uij) of 0.2 (i.e., a 1–Uij of 0.8) and byproduct formation rates of 0.15 for CF4

and 0.05 for C2F6 and use Equations I– 

8A and I–8B of this subpart. 


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(7) If your fab employs hydrocarbonfuel-based emissions control systems 

(including, but not limited to, abatement 

systems as defined at § 98.98) to control 

emissions from tools that use either NF3

in remote plasma cleaning processes or 

F2 as an input gas in any process type 

or sub-type, you must calculate the 

amount CF4 produced within and 

emitted from such systems using 

Equation I–9 using default utilization 

and by-product formation rates as 

shown in Table I–3 or I–4 of this 

subpart. A hydrocarbon-fuel-based 

emissions control system is assumed not 

to form CF4 from F2 if the electronics 

manufacturer can certify that the rate of 

conversion from F2 to CF4 is <0.1% for 

that hydrocarbon-fuel-based emissions 

control system. 

Where: 

EABCF4 = Emissions of CF4 from 

hydrocarbon-fuel-based emissions 

control systems when direct reaction 

between hydrocarbon fuel and F2 is not 

certified not to occur by the emissions 

control system manufacturer or 

electronics manufacturer, kg. 

CF2,j = Amount of F2 consumed for process 

type or sub-type j, as calculated in 

Equation I–13 of this subpart, on a fab 

basis (kg). 

UF2,j = Process utilization rate for F2 for 

process type or sub-type j (expressed as 

a decimal fraction). 

AF2,j = Within process sub-type or process 

type j, fraction of F2 used in process tools 

with hydrocarbon-fuel-based abatement 

systems that are not certified not to form 

CF4, on a fab basis, where the numerator 

is the number of tools that are equipped 

with hydrocarbon-fuel-based emissions 

control systems that are not certified not 

to form CF4 that use F2 in process type 

j and the denominator is the total 

number of tools in the fab that use F2 in 

process type j (expressed as a decimal 

fraction). 

UTF2,j = The average uptime factor of all 

abatement systems connected to process 

tools in the fab using F2 in process subtype or process type j (expressed as a 

decimal fraction). 

ABCF4,F2 = Mass fraction of F2 in process 

exhaust gas that is converted into CF4 by 

direct reaction with hydrocarbon fuel in 

a combustion abatement system. The 

default value of ABCF4,F2=0.116. 

CNF3,RPC = Amount of NF3 consumed in 

remote plasma cleaning processes, as 

calculated in Equation I–13 of this 

subpart, on a fab basis (kg). 

BF2, NF3 = By-product formation rate of F2

created as a by-product per amount of 

NF3 (kg) consumed in remote plasma 

cleaning processes (kg). 

aNF3,RPC = Within remote plasma cleaning 

processes, fraction of NF3 used in 

process tools with hydrocarbon-fuelbased abatement systems that are not 

certified not to form CF4, where the 

numerator is the number of tools running 

remote plasma cleaning processes that 

are equipped with hydrocarbon-fuelbased emissions control systems that are 

not certified not to form CF4 that use NF3

and the denominator is the total number 

of tools that run remote plasma clean 

processes in the fab that use NF3

(expressed as decimal fraction). 

UTNF3,RPC,F2 = The average uptime factor of 

all abatement systems connected to 

process tools in the fab emitting byproduct gas F2, formed from input gas 

NF3 in remote plasma cleaning 

processes, on a fab basis (expressed as a 

decimal fraction). For this equation, 

UTNF3,RPC,F2 is assumed to be equal to 

UTNF3,RPC as calculated in Equation I–15 

of this subpart. 

j = Process type or sub-type. 

* * * * * 

(e) You must calculate the amount of 

input gas i consumed, on a fab basis, for 

each process sub-type or process type j, 

using Equation I–13 of this subpart. 

Where a gas supply system serves more 

than one fab, Equation I–13 is applied 

to that gas which has been apportioned 

to each fab served by that system using 

the apportioning factors determined in 

accordance with § 98.94(c). If you elect 

to calculate emissions using the stack 

test method in paragraph (i) of this 

section and to use this paragraph to 

calculate the fraction each fluorinated 

input gas i exhausted from tools with 

abatement systems and the fraction of 

each by-product gas k exhausted from 

tools with abatement systems, you may 

substitute ‘‘The set of tools with 

abatement systems’’ for ‘‘Process subtype or process type’’ in the definition 

of ‘‘j’’ in Equation I–13 of this subpart. 

* * * * * 

(i) Stack Test Method. As an 

alternative to the default emission factor 

method in paragraph (a) of this section, 

you may calculate fab-level fluorinated 

GHG emissions using fab-specific 

emission factors developed from stack 

testing. In this case, you must comply 

with the stack test method specified in 

paragraph (i)(3) of this section. 

(1)–(2) [Reserved] 

(3) Stack system stack test method. 

For each stack system in the fab, 

measure the emissions of each 

fluorinated GHG from the stack system 

by conducting an emission test. In 

addition, measure the fab-specific 

consumption of each fluorinated GHG 

by the tools that are vented to the stack 

systems tested. Measure emissions and 

consumption of each fluorinated GHG 

as specified in § 98.94(j). Develop fabspecific emission factors and calculate 

fab-level fluorinated GHG emissions 

using the procedures specified in 

paragraph (i)(3)(i) through (viii) of this 

section. All emissions test data and 

procedures used in developing emission 

factors must be documented and 

recorded according to § 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 § 98.94(j)(3). Calculate the 

consumption for each fluorinated GHG 

for the test period. 

* * * * * 

(iii) You must calculate a fab-specific 

emission factor for each fluorinated 

GHG input gas consumed (in kg of 

fluorinated GHG emitted per kg of input 

gas i consumed) in the tools that vent to 

stack systems, as applicable, using 

Equations I–19A and I–19B or I–19A 

and I–19c of this subpart. Use Equation 

I–19A to calculate the controlled 

emissions for each fluorinated GHG that 

would result during the sampling period 

if the utilization rate for the input gas 

were equal to 0.2 (Eimax,f). If èsEi,s (the 

total measured emissions of the 

fluorinated GHG across all stack 

systems, calculated based on the results 

of Equation I–17) is less than or equal 

to Eimax,f calculated in I–19A, use 

Equation I–19B to calculate the 

emission factor for that fluorinated 

GHG. If èsEi,s is larger than the Eimax,f

calculated in I–19A, use Equation I–19C 

to calculate the emission factor and treat 

the difference between the total 

measured emissions èsEi,s and the 

maximum expected controlled 

emissions Eimax,f as a by-product of the 

other input gases, using Equation I–20 

of this subpart. 


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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 

§ 98.94(j)(3) (kg consumed). 

UTf = The total uptime of all abatement 

systems for fab f, during the sampling 

period, as calculated in Equation I–23 of 

this subpart (expressed as decimal 

fraction). If the stack system does not 

have abatement systems on the tools 

vented to the stack system, the value of 

this parameter is zero. 

aif = Fraction of input gas i emitted from tools 

with abatement systems in fab f 

(expressed as a decimal fraction), as 

calculated in Equation I–24C. 

dif = Fraction of fluorinated GHG input gas 

i destroyed or removed when fed into 

abatement systems by process tools in 

fab f, as calculated in Equation I–24A of 

this subpart (expressed as decimal 

fraction). 

f = Fab. 

i = Fluorinated GHG input gas. 

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 § 98.94(j)(3) (kg 

consumed). 

UTf = The total uptime of all abatement 

systems for fab f, during the sampling 

period, as calculated in Equation I–23 of 

this subpart (expressed as decimal 

fraction). If the stack system does not 

have abatement systems on the tools 

vented to the stack system, the value of 

this parameter is zero. 

aif = Fraction of fluorinated GHG input gas 

i exhausted from tools with abatement 

systems in fab f (expressed as a decimal 

fraction), as calculated in Equation I– 

24C. 

dif = Fraction of fluorinated GHG input gas 

i destroyed or removed when fed into 

abatement systems by process tools in 

fab f, as calculated in Equation I–24A of 

this subpart (expressed as decimal 

fraction). If the stack system does not 

have abatement systems on the tools 

vented to the stack system, the value of 

this parameter is zero. 

f = Fab. 

i = Fluorinated GHG input gas. 

s = Stack system. 

EFif = Emission factor for input gas i, from 

fab f, representing a 20-percent 

utilization rate and a 100-percent 

abatement system uptime (kg emitted/kg 

input gas consumed). 

aif = Fraction of input gas i emitted from tools 

with abatement systems in fab f 

(expressed as a decimal fraction), as 

calculated in Equation I–24C. 

dif = Fraction of fluorinated GHG input gas 

i destroyed or removed when fed into 

abatement systems by process tools in 

fab f, as calculated in Equation I–24A of 

this subpart (expressed as decimal 

fraction). 

f = Fab. 

i = Fluorinated GHG input gas. 

(iv) You must calculate a fab-specific 

emission factor for each fluorinated 

GHG formed as a by-product (in kg of 

fluorinated GHG per kg of total 

fluorinated GHG consumed) in the tools 

vented to stack systems, as applicable, 

using Equation I–20 of this subpart. 

When calculating the by-product 

emission factor for an input gas for 

which èsEi,s equals or exceeds Eimax,f, 

exclude the consumption of that input 

gas from the term ‘‘è(Activityif).’’ 

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 byproduct 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 § 98.94(j)(3) (kg 

consumed). 

UTf = The total uptime of all abatement 

systems for fab f, during the sampling 

period, as calculated in Equation I–23 of 

this subpart (expressed as decimal 

fraction). 

akif = Fraction of by-product k emitted from 

tools using input gas i with abatement 

systems in fab f (expressed as a decimal 

fraction), as calculated using Equation I– 

24D. 

dkif = Fraction of fluorinated GHG by-product 

gas k generated from input gas i 

destroyed or removed when fed into 

abatement systems by process tools in 

fab f, as calculated in Equation I–24B of 

this subpart (expressed as decimal 

fraction). 

f = Fab. 

i = Fluorinated GHG input gas. 

k = Fluorinated GHG by-product gas. 

s = Stack system. 

(v) You must calculate annual fablevel emissions of each fluorinated GHG 

consumed using Equation I–21 of this 

section. 


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Where: 

Eif = Annual emissions of fluorinated GHG 

input gas i (kg/year) from the stack 

systems for fab f. 

EFif = Emission factor for fluorinated GHG 

input gas i emitted from fab f, as 

calculated in Equation I–19 of this 

subpart (kg emitted/kg input gas 

consumed). 

Cif = Total consumption of fluorinated GHG 

input gas i in tools that are vented to 

stack systems, for fab f, for the reporting 

year, as calculated using Equation I–13 

of this subpart (kg/year). 

UTf = The total uptime of all abatement 

systems for fab f, during the reporting 

year, as calculated using Equation I–23 

of this subpart (expressed as a decimal 

fraction). 

aif = Fraction of fluorinated GHG input gas 

i emitted from tools with abatement 

systems in fab f (expressed as a decimal 

fraction), as calculated using Equation I– 

24C or I–24D. 

dif = Fraction of fluorinated GHG input gas 

i destroyed or removed when fed into 

abatement systems by process tools in 

fab f that are included in the stack testing 

option, as calculated in Equation I–24A 

of this subpart (expressed as decimal 

fraction). 

f = Fab. 

i = Fluorinated GHG input gas. 

(vi) You must calculate annual fablevel emissions of each fluorinated GHG 

by-product formed using Equation I–22 

of this section. 

Where: 

Ekf = Annual emissions of fluorinated GHG 

by-product gas k (kg/year) from the stack 

for fab f. 

EFkf = Emission factor for fluorinated GHG 

by-product gas k, emitted from fab f, as 

calculated in Equation I–20 of this 

subpart (kg emitted/kg of all fluorinated 

input gases consumed). 

Cif = Total consumption of fluorinated GHG 

input gas i in tools that are vented to 

stack systems, for fab f, for the reporting 

year, as calculated using Equation I–13 

of this subpart. 

UTf = The total uptime of all abatement 

systems for fab f, during the reporting 

year as calculated using Equation I–23 of 

this subpart (expressed as a decimal 

fraction). 

akif = Estimate of fraction of fluorinated GHG 

by-product gas k emitted in fab f from 

tools using input gas i with abatement 

systems (expressed as a decimal 

fraction), as calculated using Equation I– 

24D. 

dkif = Fraction of fluorinated GHG by-product 

k generated from input gas i destroyed or 

removed when fed into abatement 

systems by process tools in fab f that are 

included in the stack testing option, as 

calculated in Equation I–24B of this 

subpart (expressed as decimal fraction). 

f = Fab. 

i = Fluorinated GHG input gas. 

k = Fluorinated GHG by-product 

* * * * * 

(viii) When using the stack testing 

option described in paragraph (i) of this 

section and when using more than one 

DRE for the same input gas i or byproduct gas k, you must calculate the 

weighted-average fraction of each 

fluorinated input gas i and each 

fluorinated by-product gas k that has 

more than one DRE and that is 

destroyed or removed in abatement 

systems for each fab f, as applicable, by 

using Equation I–24A (for input gases) 

and Equation I–24B (for by-product 

gases) of this subpart and Table I–18 of 

this subpart. If default values are not 

available in Table I–18 for a particular 

input gas, you must use a value of 10. 

Where: 

dif = The average weighted fraction of 

fluorinated GHG input gas i destroyed or 

removed when fed into abatement 

systems by process tools in fab f 

(expressed as a decimal fraction). 

dkif = The average weighted fraction of 

fluorinated GHG by-product gas k 

generated from input gas i that is 

destroyed or removed when fed into 

abatement systems by process tools in 

fab f (expressed as a decimal fraction). 

ni,p,DREy = Number of tools that use gas i, that 

run chamber cleaning process p, and that 

are equipped with abatement systems for 

gas i that have the DRE DREy. 

mi,q,DREz = Number of tools that use gas i, that 

run etch and/or wafer cleaning 

processes, and that are equipped with 

abatement systems for gas i that have the 

DRE DREz. 

ni,p,a = Total number of tools that use gas i, 

run chamber cleaning process type p, 

and that are equipped with abatement 

systems for gas i. 

mi,q,a = Total number of tools that use gas i, 

run etch and/or wafer cleaning 

processes, and that are equipped with 

abatement systems for gas i. 

nk,i,p,DREy = Number of tools that use gas i, 

generate by-product k, that run chamber 

cleaning process p, and that are 

equipped with abatement systems for gas 

i that have the DRE DREy. 

mk,i,q,DREz = Number of tools that use gas i, 

generate by-product k, that run etch and/ 

or wafer cleaning processes, and that are 

equipped with abatement systems for gas 

i that have the DRE DREz. 

nk,i,p,a = Total number of tools that use gas i, 

generate by-product k, run chamber 

cleaning process type p, and that are 

equipped with abatement systems for gas 

i. 

mk,i,q,a = Total number of tools that use gas 

i, generate by-product k, run etch and/or 

wafer cleaning processes, and that are 

equipped with abatement systems for gas 

i. 

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 


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per tool of input gas i from process tools 

running process type q processes. 

DREy = Default or alternative certified DRE 

for gas i for abatement systems 

connected to CVD tool. 

DREz = Default or alternative certified DRE 

for gas i for abatement systems 

connected to etching and/or wafer 

cleaning tool. 

p = Chamber cleaning process sub-type. 

q = Reference process type. There is one 

process type q that consists of the 

combination of etching and/or wafer 

cleaning processes. 

f = Fab. 

i = Fluorinated GHG input gas. 

(ix) When using the stack testing 

method described in this paragraph (i), 

you must calculate the fraction each 

fluorinated input gas i exhausted in fab 

f from tools with abatement systems and 

the fraction of each by-product gas k 

exhausted from tools with abatement 

systems, as applicable, by following 

either the procedure set forth in 

paragraph (i)(3)(ix)(A) of this section or 

the procedure set forth in paragraph 

(i)(3)(ix)(B) of this section. 

(A) Use Equation I–24C (for input 

gases) and Equation I–24D (for byproduct gases) and Table I–18 of this 

subpart. If default values are not 

available in Table I–18 for a particular 

input gas, you must use a value of 10. 

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 subtype 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. 

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 byproduct 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 byproduct 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 byproduct k from input gas i and running 

chamber cleaning process p. 

mk,i,q = Total number of tools emitting byproduct 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 byproduct gas k from input gas i from tools 

running chamber cleaning process p to 

uncontrolled emissions per tool of byproduct 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 lowuse fluorinated GHG as defined in 

§ 98.98 of this subpart using the default 

utilization and by-product formation 

rates provided in Table I–11, I–12, I–13, 

I–14, or I–15 of this subpart, as 

applicable, and by using Equations I– 

8A, I–8B, I–9, and I–13 of this subpart. 

If a fluorinated GHG was not being used 

during the stack testing and does not 

meet the definition of intermittent lowuse fluorinated GHG in § 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. 

■ 27. Amend § 98.94 by revising 

paragraphs (c) introductory text, (e), 

(f)(3), (f)(4) introductory text, (f)(4)(iii), 

(j)(1) introductory text, (j)(1)(i), (j)(3) 

introductory text, (j)(5)(i), and (j)(5)(ii) 

introductory text and by removing and 

reserving paragraphs (j)(6) and (j)(8)(v). 

The revisions read as follows: 

§ 98.94 Monitoring and QA/QC 

requirements. 

* * * * * 

(c) You must develop apportioning 

factors for fluorinated GHG and N2O 

consumption (including the fraction of 

gas consumed by process tools 

connected to abatement systems as in 

Equations I–8A, I–8B, I–9, and I–10 of 

this subpart), to use in the equations of 

this subpart for each input gas i, process 

sub-type, process type, stack system, 

and fab as appropriate, using a fabspecific engineering model that is 

documented in your site GHG 

Monitoring Plan as required under 

§ 98.3(g)(5). This model must be based 

on a quantifiable metric, such as wafer 

passes or wafer starts, or direct 

measurement of input gas consumption 

as specified in paragraph (c)(3) of this 

section. To verify your model, you must 

demonstrate its precision and accuracy 

by adhering to the requirements in 

paragraphs (c)(1) and (2) of this section. 

* * * * * 

(e) If you use hydrocarbon-fuel-based 

emissions control systems to control 


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emissions from tools that use either NF3

as an input gas in remote plasma 

cleaning processes or F2 as an input gas 

in any process, and if you use a value 

less than 1 for either aF2,j or aNF3,RPC in 

Equation I–9, you must certify and 

document that the model for each of the 

systems for which you are claiming that 

it does not form CF4 from F2 has been 

tested and verified to produce less than 

0.1% CF4 from F2 and that each of the 

systems is installed, operated, and 

maintained in accordance with the 

directions of the emissions control 

system manufacturer. Hydrocarbon-fuelbased emissions control systems include 

but are not limited to abatement systems 

as defined in § 98.98 that are 

hydrocarbon-fuel-based. The rate of 

conversion from F2 to CF4 must be 

measured using a scientifically sound, 

industry-accepted method that accounts 

for dilution through the abatement 

device, such as EPA 430–R–10–003, 

adjusted to calculate the rate of 

conversion from F2 to CF4 rather than 

the DRE. Either the hydrocarbon-fuelbased emissions control system 

manufacturer or the electronics 

manufacturer may perform the 

measurement. The flow rate of F2 into 

the tested emissions control system(s) 

may be metered using a calibrated mass 

flow controller. 

(f) * * * 

(3) If you use default destruction and 

removal efficiency values in your 

emissions calculations under § 98.93(a), 

(b), and/or (i), you must certify and 

document that the abatement systems at 

your facility for which you use default 

destruction or removal efficiency values 

are specifically designed for fluorinated 

GHG or N2O abatement, as applicable, 

and that the abatement system has been 

tested by the abatement system 

manufacturer based on the methods 

specified in paragraph (f)(3)(i) of this 

section and verified to meet (or exceed) 

the default destruction or removal 

efficiency in Table I–16 for the 

fluorinated GHG or N2O under worstcase flow conditions as defined in 

paragraph (f)(3)(ii) of this section. If you 

use a verified destruction and removal 

efficiency value that is lower than the 

default in Table I–16 in your emissions 

calculations under § 98.93(a), (b), and/or 

(i), you must certify and document that 

the abatement systems at your facility 

for which you use the verified 

destruction or removal efficiency values 

are specifically designed for fluorinated 

GHG or N2O abatement, as applicable, 

and that the abatement system has been 

tested by the abatement system 

manufacturer based on the methods 

specified in paragraph (f)(3)(i) of this 

section and verified to meet or exceed 

the destruction or removal efficiency 

value used for that fluorinated GHG or 

N2O under worst-case flow conditions 

as defined in paragraph (f)(3)(ii) of this 

section. If you elect to calculate 

fluorinated GHG emissions using the 

stack test method under § 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 

§ 98.93(i)(3). 

(i) For purposes of paragraph (f)(3) of 

this section, destruction and removal 

efficiencies must be measured using a 

scientifically sound, industry-accepted 

measurement methodology that 

accounts for dilution through the 

abatement system, such as EPA 430–R– 

10–003 (incorporated by reference, see 

§ 98.7). 

(ii) Worst-case flow conditions are 

defined as the highest total fluorinated 

GHG or N2O flows through each model 

of emissions control systems (gas by gas 

and process type by process type across 

the facility) and the highest total flow 

scenarios (with N2 dilution accounted 

for) across the facility during which the 

abatement system is claimed to be 

operational. 

(4) If you calculate and report 

controlled emissions using neither the 

default destruction or removal 

efficiency values in Table I–16 of this 

subpart nor a manufacturer verified 

lower destruction or removal efficiency 

values per paragraph (f)(3) of this 

section, you must use an average of 

properly measured destruction or 

removal efficiencies for each gas and 

process sub-type or process type 

combination, as applicable, determined 

in accordance with procedures in 

paragraphs (f)(4)(i) through (vi) of this 

section. This includes situations in 

which your fab employs abatement 

systems not specifically designed for 

fluorinated GHG or N2O abatement and 

you elect to reflect emission reductions 

due to these systems. You must not use 

a default value from Table I–16 of this 

subpart for any abatement system not 

specifically designed for fluorinated 

GHG and N2O abatement, for any 

abatement system not certified to meet 

the default value from Table I–16, or for 

any gas and process type combination 

for which you have measured the 

destruction or removal efficiency 

according to the requirements of 

paragraphs (f)(4)(i) through (vi) of this 

section. 

* * * * * 

(iii) If you elect to take credit for 

abatement system destruction or 

removal efficiency before completing 

testing on 20 percent of the abatement 

systems for that gas and process subtype or process type combination, as 

applicable, you must use default 

destruction or removal efficiencies or a 

verified destruction or removal 

efficiency, if verified at a lower value, 

for a gas and process type combination. 

You must not use a default value from 

Table I–16 of this subpart for any 

abatement system not specifically 

designed for fluorinated GHG and N2O 

abatement, and must not take credit for 

abatement system destruction or 

removal efficiency before completing 

testing on 20 percent of the abatement 

systems for that gas and process subtype 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 subtype 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 § 98.98, and with the 

abatement systems connected to the 

stack system being tested operating with 

at least 90 percent uptime, averaged 

over all abatement systems, during the 

8-hour (or longer) period for each stack 

system, or at no less than 90 percent of 

the abatement system uptime rate 

measured over the previous reporting 

year, averaged over all abatement 

systems. Hydrocarbon-fuel-based 

emissions control systems that are not 

certified not to form CF4 must operate 


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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 § 98.93(i)(3), according to 

the procedures in paragraphs (j)(3)(i) 

and (ii) of this section. 

* * * * * 

(5) * * * 

(i) Annual testing. You must conduct 

an annual emissions test for each stack 

system unless you meet the criteria in 

paragraph (j)(5)(ii) of this section to skip 

annual testing. Each set of emissions 

testing for a stack system must be 

separated by a period of at least 2 

months. 

(ii) Criteria to test less frequently. 

After the first 3 years of annual testing, 

you may calculate the relative standard 

deviation of the emission factors for 

each fluorinated GHG included in the 

test and use that analysis to determine 

the frequency of any future testing. As 

an alternative, you may conduct all 

three tests in less than 3 calendar years 

for purposes of this paragraph (j)(5)(ii), 

but this does not relieve you of the 

obligation to conduct subsequent annual 

testing if you do not meet the criteria to 

test less frequently. If the criteria 

specified in paragraphs (j)(5)(ii)(A) and 

(B) of this section are met, you may use 

the arithmetic average of the three 

emission factors for each fluorinated 

GHG and fluorinated GHG byproduct for 

the current year 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. 

* * * * * 

■ 28. Amend § 98.96 by: 

■ a. Revising paragraphs (c)(1) and (2), 

(o), (p)(2), and (q)(2) and (3); 

■ b. Revising Equation I–28 in 

paragraph (r)(2); 

■ c. Revising parameters ‘‘Cif,’’ ‘‘EFkf,’’ 

‘‘af,’’ and ‘‘dkf’’ of Equation I–28 in 

paragraph (r)(2); and 

■ d. Revising paragraphs (w)(2), (y) 

introductory text, (y)(1), (y)(2)(i) and 

(iv), and (y)(4). 

The revisions read as follows: 

§ 98.96 Data reporting requirements. 

* * * * * 

(c) * * * 

(1) When you use the procedures 

specified in § 98.93(a) of this subpart, 

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 of this subpart. 

(2) When you use the procedures 

specified in § 98.93(a), each fluorinated 

GHG emitted from each process type or 

process sub-type as calculated in 

Equations I–8A and I–8B of this subpart, 

as applicable. 

* * * * * 

(o) For all hydrocarbon-fuel-based 

emissions control systems 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, 

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 emissions control 

system manufacturer, unless the 

emissions control system is included in 

the count of systems not certified to not 

form CF4 in Equation I–9. Hydrocarbonfuel-based emissions control systems 

include but are not limited to abatement 

systems as defined in § 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 § 98.94(e). If 

you make the certification based on 

testing by the emissions control system 

manufacturer, you must provide 

documentation from the emissions 

control system manufacturer that the 

rate of conversion from F2 to CF4 is 

<0.1% when tested according to the 

requirements specified in § 98.94(e). 

(p) * * * 

(2) The basis of the destruction or 

removal efficiency being used (default, 

manufacturer verified, or site-specific 

measurement according to 

§ 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 § 98.93(a), 

(b), or (i), certification that the site 

maintenance plan for abatement systems 

for which emissions are being reported 

contains 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, including but not limited 

to 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 § 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. 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) * * * 


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* * * * * 

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 

§ 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 of this 

subpart (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. 

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 of 

this subpart, which you used to calculate 

total emissions according to the 

procedures in § 98.93(i)(3) (expressed as 

a decimal fraction). 

* * * * * 

(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 

§ 98.2(i)(3), you are not required to 

submit a technology assessment report. 

(1) The first technology assessment 

report due after January 1, 2023 is due 

on March 31, 2025, 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 byproduct formation rates or default 

destruction or removal efficiency factors 

of this subpart may need to be updated. 

* * * * * 

(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 all of 

the methods specified in paragraphs 

(y)(2)(iv)(A) through (C) of this section 

if multiple fluorinated input gases are 

used. If only one fluorinated input gas 

is fed into the process, you must use 

Equations I–29a and I–29b. 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 condition used for 

the measurement. 

(A) Dominant gas method. Use 

Equation I–29a 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, you must instead use Equation 

I–29c to calculate the input gas emission 

factor for that F–GHG and Equation I– 

29d to calculate the by-product 

formation rate for that F–GHG from the 

other input F–GHGs. To calculate byproduct emission factors for all other 

measured F–GHGs, use Equation I–29b 

and assign all measured by-products to 

the dominant gas. The dominant gas is 

the carbon-containing input F–GHG fed 

into the process in the largest quantity 

(mass). If there are no carbon containing 

input F–GHGs, the dominant gas is the 

input F–GHG with the largest input 

mass. 

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 input gas i. 


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Where: 

BEFki = By-product formation rate for gas k 

from input gas i, where gas k is not an 

input gas. 

Ek = The mass emissions of by-product gas 

k. 

Massi = The mass of input gas i where i is 

the dominant gas, as defined in (A). 

i = Fluorinated GHG input gas i. 

k = By-product gas k. 

Where: Uij = Process utilization rate for fluorinated 

GHG i, process type j. 

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 where i is 

the dominant gas, as defined in (A). 

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) All-input gas method. Use 

Equation I–30a to calculate the input gas 

emission factor (1–Uij) for each input 

gas in a single test. If the result of 

Equation I–30a exceeds 0.8 for an F– 

GHG, you must use Equation I–30c to 

calculate the input gas emission factor 

for that F–GHG and Equation I–30d to 

calculate the by-product formation rate 

for that F–GHG from the other input 

gases. Use Equation I–30b 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 carboncontaining input gases. If you choose to 

assign carbon containing by-products 

only to carbon-containing input gases, 

remove the input mass of the noncarbon containing gases from the sum of 

Massi and the sum of Massg in 

Equations I–30b and I–30d, respectively. 

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. 

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. 

Where: Uij = Process utilization rate for fluorinated 

GHG i, process type j. 

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. 


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(C) Reference emission factor method. 

Calculate the input gas emission factors 

and by-product formation rates from a 

test using Equations I–31a and I–31b, 

and Table I–19 or I–20 of this subpart. 

In this case, use Equation I–31a to 

calculate the input gas emission factors 

and use Equation I–31b and I–30b to 

calculate the by-product formation rates. 

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 of 

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. 

i = Fluorinated GHG. 

g = Fluorinated GHG input gas, where gas g 

is not equal to gas i. 

r = Reference data. 

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 = By-product formation rate for gas i 

from input gas g for process type j from 

Table I–19 or I–20 of this subpart, as 

appropriate. 

Uijr = Process utilization rate for fluorinated 

GHG i, process type j, for input gas i, 

using Table I–19 or I–20 of 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 § 98.3(c)(1) 

and the certification statement in 

§ 98.3(c)(9) is provided for each facility 

for which the consolidated report is 

submitted. 

* * * * * 

■ 29. Amend § 98.97 by: 

■ a. Revising paragraphs (b), (d)(1)(iii), 

(d)(3), (d)(5)(i), (d)(6) and (7), and 

(d)(9)(i) and (ii); 

■ b. Removing and reserving paragraph 

(i)(1); and 

■ c. Revising paragraphs (i)(5) and (9) 

and (k). 

The revisions read as follows: 

§ 98.97 Records that must be retained. 

* * * * * 

(b) If you use hydrocarbon-fuel-based 

emissions control systems to control 

emissions from tools that use either NF3

as an input gas in remote plasma 

cleaning processes or F2 as an input gas 

in any process, and if you use a value 

less than 1 for either aF2,j or aNF3,RPC in 

Equation I–9, 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 emission 

control system 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, 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 emissions control 

system manufacturer to make the 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 § 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 § 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 after January 1, 2023, 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 


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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 of this 

subpart, as 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. 

(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 of this 

subpart, 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 § 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 § 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 § 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. 

(ii) The site maintenance plan for 

abatement systems must include a 

defined preventative maintenance 

process and checklist. Preventative 

maintenance must include, but is not 

limited to, calibration of pump purge 

flow indicators. Pump purge flow 

indicators must be calibrated each time 

a vacuum pump is serviced or 

exchanged. 

* * * * * 

(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 byproduct, as calculated using Equations 

I–19A, I–19B, I–19C and I–20 of 

§ 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. 

* * * * * 

(k) Annual gas consumption for each 

fluorinated GHG and N2O as calculated 

in Equation I–11 of this subpart, 

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 of this subpart, the 

chemical name of the GHG used, the 

annual consumption of the gas, and a 

brief description of its use. 

* * * * * 

■ 30. Amend § 98.98 by adding in 

alphabetical order a definition for 

‘‘Hydrocarbon-fuel based emission 

control systems’’ and revising the 

definition of ‘‘Operational mode’’ to 

read as follows: 

§ 98.98 Definitions. 

* * * * * 

Hydrocarbon-fuel based emission 

control systems 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 includes 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 

§ 98.94(f)(1) and defined in 

§ 98.97(d)(9). This includes being 

properly operated within the range of 

parameters as specified in the site 

maintenance plan for abatement systems 

and within the range of parameters as 

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 

and within the range of parameters as 

specified in the DRE certification 

documentation. 

* * * * * 

■ 31. Revise table I–1 to subpart I of part 

98 to read as follows: 

TABLE I–1 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS FOR MANUFACTURING CAPACITY-BASED THRESHOLD

APPLICABILITY DETERMINATION

Product type 

Emission factors EFi 

CF4 C2F6 CHF3 c-C4F8 C3F8 NF3 SF6 N2O 

Semiconductors (kg/m2) ................................... 0.9 1.0 0.04 NA 0.05 0.04 0.20 NA 

LCD (g/m2) ....................................................... 0.65 NA 0.0024 0.00 NA 1.29 4.14 17.06 

MEMS (kg/m2) ................................................. 0.015 NA NA 0.076 NA NA 1.86 NA 

Notes: NA denotes not applicable based on currently available information. 


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■ 32. Redesignate table I–2 to subpart I 

of part 98 as table I–21 to subpart I of 

part 98. 

■ 33. Add new table I–2 to subpart I of 

part 98 in numerical order to read as 

follows: 

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 

■ 34. Revise table I–3 to subpart I of part 

98 to read as follows: 

TABLE I–3 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1-Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR 150 MM AND 200 MM WAFER SIZES

Process type/ 

sub-type 

Process gas i 

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. 

■ 35. Revise table I–4 to subpart I of part 

98 to read as follows: 

TABLE I–4 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1-Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR 300 MM AND 450 MM WAFER SIZE

Process type/ 

sub-type 

Process gas i 

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 0.18 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 


jspears on DSK121TN23PROD with PROPOSALS2
37060 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

TABLE I–4 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1-Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR 300 MM AND 450 MM WAFER SIZE— 

Continued 

Process type/ 

sub-type 

Process gas i 

CF4 C2F6 CHF3 CH2F2 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O 

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 

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. 

■ 36. Revise table I–8 to subpart I of part 

98 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 

■ 37. Revise table I–11 to subpart I of 

part 98 to read as follows: 

TABLE I–11 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1-Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR USE WITH THE STACK TEST METHOD

[150 mm and 200 mm Wafers] 

All processes 

Process gas i 

CF4 C2F6 CHF3 CH2F2 C2HF5 CH3F C3F8 C4F8 NF3

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 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37061 

TABLE I–11 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1-Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR USE WITH THE STACK TEST METHOD—Continued 

[150 mm and 200 mm Wafers] 

All processes 

Process gas i 

CF4 C2F6 CHF3 CH2F2 C2HF5 CH3F C3F8 C4F8 NF3

NF3

Remote SF6 C4F6 C5F8 C4F8O 

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. 

■ 38. Revise table I–12 to subpart I of 

part 98 to read as follows: 

TABLE I–12 TO SUBPART I OF PART 98—DEFAULT EMISSION FACTORS (1-Uij) FOR GAS UTILIZATION RATES (Uij) AND BYPRODUCT FORMATION RATES (Bijk) FOR SEMICONDUCTOR MANUFACTURING FOR USE WITH THE STACK TEST METHOD

[300 mm and 450 mm Wafers] 

All processes 

Process gas i 

CF4 C2F6 CHF3 CH2F2 CH3F C3F8

C3F8

Remote C4F8 NF3 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 

■ 39. Revise table I–16 to subpart I of 

part 98 to read as follows: 

TABLE I–16 TO SUBPART I OF PART 98—DEFAULT EMISSION DESTRUCTION OR REMOVAL EFFICIENCY (DRE) FACTORS

FOR ELECTRONICS MANUFACTURING

Manufacturing type/process type/gas Default DRE 

(percent) 

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 ....................................................................................................................................................................................................... 88 

All other carbon-based fluorinated GHGs used in Semiconductor Manufacturing ............................................................................. 60 

N2O Processes 

CVD and all other N2O-using processes ............................................................................................................................................ 60 

■ 40. Add table I–18 to subpart I of part 

98 to read as follows: 


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37062 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

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 

Gas CF4 C2F6 c-C4F8 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 0.12 

gCH2F2,i ............................................................. NA NA NA NA NA NA NA 55 

gCH3F,i ............................................................... NA NA NA NA NA NA NA 16 

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 

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 you use the corresponding g in this table. For all 

other tools and processes, a default g of 10 must be used. 

■ 41. Add table I–19 to subpart I of part 

98 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 type/subtype 

Process gas i 

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 0.089 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 


jspears on DSK121TN23PROD with PROPOSALS2
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■ 42. Add table I–20 to subpart I of part 

98 to read as follows: 

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 type/ 

sub-type 

Process gas i 

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 0.0083 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 

Subpart N—Glass Production 

■ 43. Amend § 98.146 by revising 

paragraphs (a)(2) and (b)(3) to read as 

follows: 

§ 98.146 Data reporting requirements. 

* * * * * 

(a) * * * 

(2) Annual quantity of glass produced 

(tons), by glass type, from each 

continuous glass melting furnace and 

from all furnaces combined. 

(b) * * * 

(3) Annual quantity of glass produced 

(tons), by glass type, from each 

continuous glass melting furnace and 

from all furnaces combined. 

* * * * * 

■ 44. Amend § 98.147 by revising 

paragraphs (a)(1) and (b)(1) to read as 

follows: 

§ 98.147 Records that must be retained. 

* * * * * 

(a) * * * 

(1) Monthly glass production rate for 

each continuous glass melting furnace, 

by glass type (tons). 

* * * * * 

(b) * * * 

(1) Monthly glass production rate for 

each continuous glass melting furnace, 

by glass type (metric tons). 

* * * * * 

Subpart P—Hydrogen Production 

■ 45. Amend § 98.163 by revising the 

introductory text and paragraph (b) 

introductory text and adding paragraph 

(d) to read as follows: 

§ 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 (d) 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 hydrogen production 

by following paragraphs (b)(1) through 

(3) of this section. Adjust the emissions 

estimated using paragraphs (b)(1) 

through (b)(3) by correcting for non-CO2

carbon produced, if applicable, 

according to paragraph (d) of this 

section. The carbon content and 

molecular weight shall be obtained from 

the analyses conducted in accordance 

with § 98.164(b)(2), (b)(3), or (b)(4), as 

applicable, or from the missing data 

procedures in § 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. 

* * * * * 

(d) If carbon other than CO2 is 

collected and transferred off site or if 

methanol is intentionally produced as a 

desired product, you must correct the 


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37064 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

CO2 emissions determined in paragraph 

(b) of this section to determine the net 

CO2 emissions according to Equation P– 

4 of this section. 

CO2,net = Annual net CO2 process emissions 

from hydrogen production unit (metric 

tons/yr). 

CO2,p = Annual CO2 process emissions 

arising from fuel and feedstock 

consumption based on fuel type ‘‘p’’ 

(metric tons/yr). 

p = index for fuel or feedstock type; 1 

indicates gaseous fuel or feedstocks; 2 

indicates liquid fuel or feedstocks; and 3 

indicates solid fuel or feedstocks 

Coffsite,n = Mass of carbon other than CO2 or 

methanol collected from the hydrogen 

production unit and transferred off site, 

from company records for month n 

(metric tons carbon). 

MeOHn = Mass of methanol intentionally 

produced as a desired product from the 

hydrogen production unit, from 

company records for month n (metric 

tons). If the methanol product has a 99.5 

weight percent or higher purity, use the 

mass of methanol product produced; 

otherwise, you must correct that mass of 

product produced by the methanol 

purity (determined from company 

records) to determine the mass of 

methanol intentionally produced. 

k = Months in the year. 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

44/32 = Ratio of molecular weights, CO2 to 

methanol. 

■ 46. Amend § 98.164 by revising 

paragraphs (b)(2) through (4) and (b)(5) 

introductory text and adding paragraph 

(b)(5)(xix) to read as follows: 

§ 98.164 Monitoring and QA/QC 

requirements. 

* * * * * 

(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) using the 

applicable methods in paragraph (b)(5) 

of this section. For non-hydrocarbon 

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 determine the 

carbon content and the molecular 

weight annually using the product 

specification’s maximum carbon content 

and molecular weight rather than using 

the methods specified in paragraph 

(b)(5) of this section. 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 using the applicable methods 

in 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) using the applicable 

methods in paragraph (b)(5) of this 

section. For non-hydrocarbon 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 determine 

the carbon content annually using the 

product specification’s maximum 

carbon content rather than using the 

methods specified in paragraph (b)(5) of 

this section. 

(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) using the 

applicable methods in paragraph (b)(5) 

of this section. 

(5) Except as provided in paragraphs 

(b)(2) and (3) of this section for certain 

non-hydrocarbon feedstocks, 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 § 98.3(g)(5). 

* * * * * 

(xix) For non-hydrocarbon fuels and 

feedstocks, 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. 

■ 47. Amend § 98.166 by revising the 

introductory text and paragraphs (b)(1) 

and (d) to read as follows: 

§ 98.166 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraph (a) or (b) of this section, as 

appropriate, and paragraphs (c) through 

(e) of this section: 

* * * * * 

(b) * * * 

(1) Unit identification number and 

annual CO2 emissions (determined in 

accordance with § 98.163(b) or (d), as 

applicable). 

* * * * * 

(d) Annual quantity of carbon other 

than CO2 collected and transferred off 

site in either gas, liquid, or solid forms 

(metric tons carbon), excluding 

methanol, for each process unit. 

* * * * * 

■ 48. Amend § 98.167 by revising 

paragraph (b) and paragraph (e) 

introductory text and adding paragraphs 

(e)(13) and (14) to read as follows: 

§ 98.167 Records that must be retained. 

* * * * * 

(b) If a CEMS is not used to measure 

CO2 emissions, then you must retain 

records of all analyses and calculations 

conducted to determine the values 

reported in § 98.166(b) through (e). 

* * * * * 

(e) You must keep a record of the file 

generated by the verification software 

specified in § 98.5(b) for the applicable 

data specified in paragraphs (e)(1) 

through (14) of this section. 

Retention of this file satisfies the 

recordkeeping requirement for the data 

in paragraphs (e)(1) through (14) of this 

section for each hydrogen production 

unit. 

* * * * * 

(13) Monthly mass of carbon other 

than CO2 or methanol collected and 

transferred off site (metric tons carbon) 

(Equation P–4). 

(14) Monthly mass of methanol 

intentionally produced as a desired 

product (metric tons) (Equation P–4). 


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Subpart Q—Iron and Steel Production 

■ 49. Amend § 98.173 by revising 

Equation Q–5 in paragraph (b)(1)(v) to 

read as follows: 

§ 98.173 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(1) * * * 

(v) * * * 

* * * * * 

■ 50. Amend § 98.174 by: 

■ a. Revising paragraph (b)(2) 

introductory text; 

■ b. Redesignating paragraph (b)(2)(vi) 

as paragraph (b)(2)(vii); and 

■ c. Adding new paragraph (b)(2)(vi). 

The revision and addition read as 

follows: 

§ 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 § 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 (b)(2)(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 § 98.7) as applicable for 

steel. 

* * * * * 

■ 51. Amend § 98.176 by revising 

paragraphs (e)(2) and (g) to read as 

follows: 

§ 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 

§ 98.174(b)(2). 

* * * * * 

(g) For each unit, the type of unit, the 

annual production capacity, and annual 

operating hours. 

* * * * * 

Subpart S—Lime Manufacturing 

■ 52. Amend § 98.193 by revising 

paragraph (b)(2)(iv) to read as follows: 

§ 98.193 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(2) * * * 

(iv) You must calculate annual net 

CO2 process emissions for all lime kilns 

using Equation S–4 of this section: 

Where: 

ECO2, net = Annual net CO2 process emissions 

from lime production from all lime kilns 

(metric tons/year). 

EFLIME,i,n = Emission factor for lime type i 

produced, in calendar month n (metric 

tons CO2/ton lime) from Equation S–1 of 

this section. 

MLIME,i,n = Weight or mass of lime type i 

produced in calendar month n (tons). 

EFLKD,i,n = Emission factor of calcined 

byproducts or wastes sold for lime type 

i in calendar month n, (metric tons CO2/ 

ton byproduct or waste) from Equation 

S–2 of this section. 

MLKD,i,n = Monthly weight or mass of calcined 

byproducts or waste sold (such as lime 

kiln dust, LKD) for lime type i in 

calendar month n (tons). 

Ewaste,i = Annual CO2 emissions for calcined 

lime byproduct or waste type i that is not 

sold (metric tons CO2) from Equation S– 

3 of this section. 

Eproduct,n = Monthly amount of CO2 from lime 

production that is captured for use in all 

on-site processes in calendar month n, as 

described in § 98.196(b)(17) (metric 

tons). 

t = Number of lime types produced 

b = Number of calcined byproducts or wastes 

that are sold. 

z = Number of calcined byproducts or wastes 

that are not sold. 

* * * * * 

■ 53. Amend § 98.196 by: 

■ a. Revising paragraph (a) introductory 

text; 

■ b. Adding paragraphs (a)(9) through 

(14); 

■ c. Revising paragraphs (b) 

introductory text, (b)(1), (b)(17) 

introductory text, and (b)(17)(i); and 

■ d. Adding paragraphs (b)(22) and (23). 

The revisions and additions read as 

follows: 

§ 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 § 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 


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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. 

(1) Annual net CO2 process emissions 

from all lime kilns combined (metric 

tons). 

* * * * * 

(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. 

* * * * * 

(22) Annual average results of 

chemical composition analysis of all 

lime byproducts or wastes not sold. 

(23) Annual quantity (tons) of all lime 

byproducts or wastes not sold. 

■ 54. Amend § 98.197 by revising 

paragraph (c) introductory text and 

adding paragraph (c)(10) to read as 

follows: 

§ 98.197 Records that must be retained. 

* * * * * 

(c) You must keep a record of the file 

generated by the verification software 

specified in § 98.5(b) for the applicable 

data specified in paragraphs (c)(1) 

through (10) of this section. Retention of 

this file satisfies the recordkeeping 

requirement for the data in paragraphs 

(c)(1) through (10) of this section. 

* * * * * 

(10) Monthly amount of CO2 from 

lime production that is captured for use 

in all on-site processes, as described in 

§ 98.196(b)(17) (metric tons) (Equation 

S–4). 

Subpart W—Petroleum and Natural 

Gas Systems 

■ 55. Amend § 98.230 by revising 

paragraph (a)(3) to read as follows: 

§ 98.230 Definition of the source category. 

(a) * * * 

(3) Onshore natural gas processing. 

Natural gas processing means the forced 

extraction of natural gas liquids (NGLs) 

from field gas, fractionation of mixed 

NGLs to natural gas products, or both. 

Natural gas processing does not include 

a Joule-Thomson valve, a dew point 

depression valve, or an isolated or 

standalone Joule-Thomson skid. This 

segment also includes all residue gas 

compression equipment owned or 

operated by the natural gas processing 

plant. 

* * * * * 

■ 56. Amend § 98.232 by: 

■ a. Revising paragraphs (b) and (c)(21); 

■ b. Adding paragraph (c)(23); 

■ c. Revising paragraph (d)(7); 

■ d. Adding paragraphs (d)(8) and (9); 

■ e. Revising paragraph (e)(8); 

■ f. Adding paragraph (e)(9); 

■ g. Revising paragraphs (f)(6) and (8); 

■ h. Adding paragraph (f)(9); 

■ i. Revising paragraphs (g)(6) and (7); 

■ j. Adding paragraph (g)(8); 

■ k. Revising paragraphs (h)(7) and (8); 

■ l. Adding paragraphs (h)(9) and (10) 

and (i)(8); 

■ m. Revising paragraph (j)(10); 

■ n. Adding paragraph (j)(13); and 

■ o. Revising paragraph (m). 

The revisions and additions read as 

follows: 

§ 98.232 GHGs to report. 

* * * * * 

(b) For offshore petroleum and natural 

gas production, report CO2, CH4, and 

N2O emissions from equipment leaks, 

vented emission, and flare emission 

source types as identified in the data 

collection and emissions estimation 

study conducted by BOEM in 

compliance with 30 CFR 550.302 

through 304 and CO2 and CH4 emissions 

from other large release events. Offshore 

platforms do not need to report portable 

emissions. 

(c) * * * 

(21) Equipment leaks listed in 

paragraph (c)(21)(i) or (ii) of this section, 

as applicable: 

(i) Equipment leaks from components 

including valves, connectors, open 

ended lines, pressure relief valves, 

pumps, flanges, and other components 

(such as instruments, loading arms, 

stuffing boxes, compressor seals, dump 

lever arms, and breather caps, but does 

not include components listed in 

paragraph (c)(11) or (19) of this section, 

and it does not include thief hatches or 

other openings on a storage vessel). 

(ii) Equipment leaks from major 

equipment including wellheads, 

separators, meters/piping, compressors, 

acid gas removal units, dehydrators, 

heater treaters, and storage vessels. 

* * * * * 

(23) Other large release events. 

(d) * * * 

(7) Equipment leaks from valves, 

connectors, open ended lines, pressure 

relief valves, and meters, and equipment 

leaks from all other components in gas 

service that either are subject to 

equipment leak standards for processing 

plants in part 60, subpart OOOOb of this 

chapter, or an applicable approved state 

plan or applicable Federal plan in part 

62 of this chapter or that you elect to 

survey using a leak detection method 

described in § 98.234(a). 

(8) Natural gas pneumatic device 

venting. 

(9) Other large release events. 

(e) * * * 

(8) Equipment leaks from all other 

components that are not listed in 

paragraph (e)(1), (2), or (7) of this 

section and either are subject to the well 

site or compressor station fugitive 

emissions standards in § 60.5397a of 

this chapter, the fugitive emissions 

standards for well sites and compressor 

stations in part 60, subpart OOOOb of 

this chapter, or an applicable approved 

state plan or applicable Federal plan in 

part 62 of this chapter, or that you elect 

to survey using a leak detection method 

described in § 98.234(a). The other 

components subject to this paragraph 

(e)(8) also do not include thief hatches 

or other openings on a storage vessel. 

(9) Other large release events. 

(f) * * * 

(6) Equipment leaks from all other 

components that are associated with 

storage stations, are not listed in 

paragraph (f)(1), (2), or (5) of this 

section, and either are subject to the 

well site or compressor station fugitive 

emissions standards in § 60.5397a of 

this chapter, the fugitive emissions 

standards for well sites and compressor 

stations in part 60, subpart OOOOb of 

this chapter, or an applicable approved 

state plan or applicable Federal plan in 

part 62 of this chapter or that you elect 

to survey using a leak detection method 

described in § 98.234(a). 

* * * * * 

(8) Equipment leaks from all other 

components that are associated with 

storage wellheads, are not listed in 

paragraph (f)(1), (2), or (7) of this 

section, and either are subject to the 

well site or compressor station fugitive 

emissions standards in § 60.5397a, of 


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this chapter, the fugitive emissions 

standards for well sites and compressor 

stations in part 60, subpart OOOOb of 

this chapter, or an applicable approved 

state plan or applicable Federal plan in 

part 62 of this chapter or that you elect 

to survey using a leak detection method 

described in § 98.234(a). 

(9) Other large release events. 

(g) * * * 

(6) Equipment leaks from all 

components in gas service that are 

associated with a vapor recovery 

compressor, are not listed in paragraph 

(g)(1) or (2) of this section, and either 

are subject to the well site or 

compressor station fugitive emissions 

standards in § 60.5397a of this chapter, 

the fugitive emissions standards for well 

sites and compressor stations in part 60, 

subpart OOOOb of this chapter, or an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter or that you elect to survey 

using a leak detection method described 

in § 98.234(a). 

(7) Equipment leaks from all 

components in gas service that are not 

associated with a vapor recovery 

compressor, are not listed in paragraph 

(g)(1) or (2) of this section, and either 

are subject to the well site or 

compressor station fugitive emissions 

standards in § 60.5397a of this chapter, 

the fugitive emissions standards for well 

sites and compressor stations in part 60, 

subpart OOOOb of this chapter, or an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter or that you elect to survey 

using a leak detection method described 

in § 98.234(a). 

(8) Other large release events. 

(h) * * * 

(7) Equipment leaks from all 

components in gas service that are 

associated with a vapor recovery 

compressor, are not listed in paragraph 

(h)(1) or (2) of this section, and either 

are subject to the well site or 

compressor station fugitive emissions 

standards in § 60.5397a of this chapter, 

the fugitive emissions standards for well 

sites and compressor stations in part 60, 

subpart OOOOb of this chapter, or an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter or that you elect to survey 

using a leak detection method described 

in § 98.234(a). 

(8) Equipment leaks from all 

components in gas service that are not 

associated with a vapor recovery 

compressor, are not listed in paragraph 

(h)(1) or (2) of this section, and either 

are subject to the well site or 

compressor station fugitive emissions 

standards in § 60.5397a of this chapter, 

the fugitive emissions standards for well 

sites and compressor stations in 40 CFR 

part 60, subpart OOOOb of this chapter, 

or an applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter or that you elect to survey 

using a leak detection method described 

in § 98.234(a). 

(9) Acid gas removal vents. 

(10) Other large release events. 

(i) * * * 

(8) Other large release events. 

(j) * * * 

(10) Equipment leaks listed in 

paragraph (j)(10)(i) or (ii) of this section, 

as applicable: 

(i) Equipment leaks from components 

including valves, connectors, open 

ended lines, pressure relief valves, 

pumps, flanges, and other components 

(such as instruments, loading arms, 

stuffing boxes, compressor seals, dump 

lever arms, and breather caps, but does 

not include components in paragraph 

(j)(8) or (9) of this section, and it does 

not include thief hatches or other 

openings on a storage vessel). 

(ii) Equipment leaks from major 

equipment including wellheads, 

separators, meters/piping, compressors, 

acid gas removal units, dehydrators, 

heater treaters, and storage vessels. 

* * * * * 

(13) Other large release events. 

* * * * * 

(m) For onshore natural gas 

transmission pipeline, report pipeline 

blowdown CO2 and CH4 emissions from 

blowdown vent stacks and CO2 and CH4

emissions from other large release 

events. 

■ 57. Amend § 98.233 by: 

■ a. Revising paragraphs (a), (c), (d) 

introductory text, and (d)(4)(vi); 

■ b. Adding paragraph (d)(12); 

■ c. Revising paragraphs (e) 

introductory text, (e)(1) introductory 

text; (e)(1)(x), and (e)(2) introductory 

text; 

■ d. Revising parameter ‘‘Count’’ of 

Equation W–5 in paragraph (e)(2); 

■ e. Removing and reserving paragraph 

(e)(3); 

■ f. Removing paragraph (e)(4); 

■ g. Redesignating paragraphs (e)(5) and 

(6) as (e)(4) and (5), respectively; 

■ h. Revising newly redesignated 

paragraphs (e)(4) and (5) and paragraphs 

(g)(4), (h)(2), (i) introductory text, and 

(i)(2) introductory text; 

■ i. Revising parameters ‘‘Ta’’ and ‘‘Pa’’ 

of Equation W–14A in paragraph 

(i)(2)(i); 

■ j. Revising parameters ‘‘Ta,p’’, ‘‘Pa,b,p’’, 

and ‘‘Pa,e,p’’ of Equation W–14B in 

paragraph (i)(2)(i); 

■ k. Adding paragraph (i)(2)(iv); 

■ l. Revising paragraphs (j) introductory 

text, (j)(1) introductory text, (j)(1)(iii), 

(iv), and (vii), and (j)(2); 

■ m. Revising parameter ‘‘Count’’ of 

Equation W–15 in paragraph (j)(3); 

■ n. Revising paragraphs (j)(4) through 

(6), (k)(5), (l)(6), and (m)(3) introductory 

text; 

■ o. Revising parameters ‘‘Vp,q’’ and 

‘‘SGp,q’’ of Equation W–18 in paragraph 

(m)(3); 

■ p. Revising paragraphs (m)(5), (n) 

introductory text, (n)(1), (n)(2) 

introductory text, and (n)(5); 

■ q. Removing and reserving paragraph 

(n)(9); 

■ r. Revising paragraphs (o) 

introductory text, (o)(1)(i) introductory 

text, (o)(1)(i)(A) through (C), (o)(2) 

introductory text, (o)(2)(i) introductory 

text, and (o)(2)(ii); 

■ s. Adding paragraph (o)(2)(iii); 

■ t. Removing and reserving paragraph 

(o)(4)(ii)(D); 

■ u. Revising paragraphs (o)(4)(ii)(E) 

and (o)(6)(i) introductory text; 

■ v. Revising parameter ‘‘m’’ of 

Equation W–21 in paragraph (o)(6)(i); 

■ w. Revising paragraph (o)(6)(ii) 

introductory text; 

■ x. Revising parameter ‘‘m’’ of 

Equation W–22 in paragraph (o)(6)(ii); 

■ y. Revising paragraph (o)(6)(iii) 

introductory text; 

■ z. Revising parameter ‘‘m’’ of Equation 

W–23 in paragraph (o)(6)(iii); 

■ aa. Revising parameter ‘‘Tg’’ of 

Equation W–24B in paragraph (o)(8); 

■ bb. Revising paragraph (o)(10) 

introductory text; 

■ cc. Revising parameter ‘‘Count’’ of 

Equation W–25 in paragraph (o)(10); 

■ dd. Revising paragraphs (p) 

introductory text, (p)(1)(i), (p)(2) 

introductory text, (p)(2)(ii) introductory 

text, (p)(2)(ii)(C), (p)(2)(iii)(A), and 

(p)(4)(ii)(C); 

■ ee. Removing and reserving paragraph 

(p)(4)(ii)(D); 

■ ff. Revising paragraphs (p)(4)(ii)(E), 

(p)(6)(ii) introductory text, (p)(6)(iii) 

introductory text, and (p)(10) 

introductory text; 

■ gg. Revising parameter ‘‘Count’’ of 

Equation W–29D in paragraph (p)(10); 

■ hh. Revising paragraphs (q) 

introductory text, (q)(1), and (q)(2) 

introductory text; 

■ ii. Revising parameter ‘‘EFs,p’’ of 

Equation W–30 in paragraph (q)(2) 

introductory text; 

■ jj. Revising paragraphs (q)(2)(i), (iii), 

(v), (x), and (xi); 

■ kk. Adding paragraph (q)(3); 

■ ll. Revising paragraph (r) introductory 

text; 

■ mm. Revising parameters ‘‘Es,e,I,’’ 

‘‘Es,MR,I,’’ ‘‘Counte,’’ ‘‘CountMR,’’ and 

‘‘EFs,e’’ of Equations W–32A and W–32B 

in paragraph (r) introductory text; 

■ nn. Revising paragraphs (r)(2), (r)(6)(i) 

and (ii), and (s); 


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■ oo. Revising parameter ‘‘Za’’ of 

Equation W–34 in paragraph (t)(2); 

■ pp. Removing the unnumbered text 

‘‘You may use either a default 

compressibility factor of 1, or a sitespecific compressibility factor based on 

actual temperature and pressure 

conditions.’’ after parameter ‘‘Za’’ of 

Equation W–34 in paragraph (t)(2); and 

■ qq. Revising paragraphs (u)(2)(ii), (y), 

and (z). 

The revisions and additions read as 

follows: 

§ 98.233 Calculating GHG emissions. 

* * * * * 

(a) Natural gas pneumatic device 

venting. For all natural gas pneumatic 

devices at onshore natural gas 

processing facilities, onshore natural gas 

transmission compression facilities, and 

underground natural gas storage 

facilities, use methods specified in 

paragraphs (a)(1) through (5) of this 

section to calculate CH4 and CO2

emissions. For all continuous high bleed 

and continuous low bleed natural gas 

pneumatic devices at an onshore 

petroleum and natural gas production 

facility or an onshore petroleum and 

natural gas gathering and boosting 

facility, use methods specified in 

paragraphs (a)(1) through (5) of this 

section to calculate CH4 and CO2

emissions. For intermittent bleed 

natural gas pneumatic devices at an 

onshore petroleum and natural gas 

production facility or an onshore 

petroleum and natural gas gathering and 

boosting facility that are subject to 

monitoring requirements in part 60, 

subpart OOOOb of this chapter or an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter, use the methods specified 

in paragraph (a)(6) of this section to 

calculate CH4 and CO2 emissions from 

those pneumatic devices. For 

intermittent bleed natural gas 

pneumatic devices at an onshore 

petroleum and natural gas production 

facility or an onshore petroleum and 

natural gas gathering and boosting 

facility that are not subject to 

monitoring requirements in part 60, 

subpart OOOOb of this chapter or an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter, you may either elect to 

monitor your intermittent bleed natural 

gas pneumatic devices at least annually 

following the methods specified in part 

60, subpart OOOOb of this chapter or an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter, as applicable, and use the 

methods specified in paragraph (a)(6) of 

this section to calculate CH4 and CO2

emissions from your natural gas 

intermittent bleed pneumatic devices or 

use the methods specified in paragraphs 

(a)(1) through (5) of this section to 

calculate CH4 and CO2 emissions from 

your natural gas intermittent bleed 

pneumatic devices. 

(1) Calculate CH4 and CO2 volumetric 

emissions from continuous high bleed, 

continuous low bleed, and intermittent 

bleed natural gas pneumatic devices 

using Equation W–1A of this section. 

Where: 

Es,i = Annual total volumetric GHG emissions 

at standard conditions in standard cubic 

feet per year from natural gas pneumatic 

device vents, of types ‘‘t’’ (continuous 

high bleed, continuous low bleed, 

intermittent bleed), for GHGi. 

Countt = Total number of natural gas 

pneumatic devices of type ‘‘t’’ 

(continuous high bleed, continuous low 

bleed, intermittent bleed) as determined 

in paragraph (a)(1) or (a)(2) of this 

section. 

EFt = Population emission factors for natural 

gas pneumatic device vents (in standard 

cubic feet per hour per device) of each 

type ‘‘t’’ listed in Tables W–1A, W–2B, 

W–3B, and W–4B to this subpart for 

onshore petroleum and natural gas 

production and onshore petroleum and 

natural gas gathering and boosting, 

onshore natural gas processing, onshore 

natural gas transmission compression, 

and underground natural gas storage 

facilities, respectively. 

GHGi = For onshore petroleum and natural 

gas production facilities, onshore 

petroleum and natural gas gathering and 

boosting facilities, onshore natural gas 

processing, onshore natural gas 

transmission compression facilities, and 

underground natural gas storage 

facilities, concentration of GHGi, CH4 or 

CO2, in produced natural gas or 

processed natural gas for each facility as 

specified in paragraphs (u)(2)(i) through 

(iv) of this section. 

Tt = Average estimated number of hours in 

the operating year the devices, of each 

type ‘‘t’’, were in service (i.e., supplied 

with natural gas) using engineering 

estimates based on best available data. 

Default is 8,760 hours. 

(2) For all industry segments, 

determine ‘‘Countt’’ for Equation W–1A 

of this subpart for each type of natural 

gas pneumatic device (continuous high 

bleed, continuous low bleed, and 

intermittent bleed) by counting the 

devices, except as specified in 

paragraph (a)(3) of this section. The 

reported number of devices must 

represent the total number of devices for 

the reporting year. 

(3) For the onshore petroleum and 

natural gas production industry 

segment, you have the option in the first 

two consecutive calendar years to 

determine ‘‘Countt’’ for Equation W–1A 

of this section for each type of natural 

gas pneumatic device (continuous high 

bleed, continuous low bleed, and 

intermittent bleed) using engineering 

estimates based on best available data. 

For the onshore petroleum and natural 

gas gathering and boosting industry 

segment, you have the option in the first 

two consecutive calendar years to 

determine ‘‘Countt’’ for Equation W–1A 

for each type of natural gas pneumatic 

device (continuous high bleed, 

continuous low bleed, and intermittent 

bleed) using engineering estimates 

based on best available data. 

(4) For all industry segments, 

determine the type of pneumatic device 

using engineering estimates based on 

best available information. 

(5) Calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculations in paragraph (v) of 

this section. 

(6) Calculate CH4 and CO2 volumetric 

emissions using Equation W–1B of this 

section from natural gas intermittent 

bleed pneumatic devices that are 

monitored according to the 

requirements in this paragraph (a)(6). 


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Where: 

Ei = Annual total volumetric emissions of 

GHGi from natural gas intermittent bleed 

pneumatic devices in standard cubic 

feet. 

GHGi = Concentration of GHGi, CH4, or CO2, 

in natural gas supplied to the 

intermittent bleed device as defined in 

paragraph (u)(2) of this section. 

x = Total number of intermittent bleed 

devices detected as malfunctioning in 

any pneumatic device monitoring survey 

during the year. A component found as 

malfunctioning in two or more surveys 

during the year is counted as one 

malfunctioning component. 

24.1 = Whole gas emission factor for 

malfunctioning intermittent bleed 

natural gas pneumatic devices, in 

standard cubic feet per hour per device. 

Tz = The total time the surveyed pneumatic 

device ‘‘z’’ was in service (i.e., supplied 

with natural gas) and assumed to be 

leaking, in hours. If one pneumatic 

device monitoring survey is conducted 

in the calendar year, assume the device 

found malfunctioning was 

malfunctioning for the entire calendar 

year. If multiple pneumatic device 

monitoring surveys are conducted in the 

calendar year, assume a device found 

malfunctioning in the first survey was 

malfunctioning since the beginning of 

the year until the date of the survey; 

assume a device found malfunctioning in 

the last survey of the year was 

malfunctioning from the preceding 

survey through the end of the year; 

assume a device found malfunctioning in 

a survey between the first and last 

surveys of the year was malfunctioning 

since the preceding survey until the date 

of the survey; and sum times for all 

malfunctioning periods. 

0.3 = Whole gas emission factor for properly 

operating intermittent bleed natural gas 

pneumatic devices, in standard cubic 

feet per hour. 

Count = Total number of intermittent bleed 

devices that were never observed to be 

malfunctioning during any monitoring 

survey during the year. 

Tavg = The average time the pneumatic 

devices that were never observed to be 

malfunctioning during any monitoring 

survey were in service (i.e., supplied 

with natural gas) using engineering 

estimates based on best available data. 

Default is 8,760 hours. 

(i) You must conduct pneumatic 

device monitoring surveys using the 

methods in either paragraph (a)(6)(i) or 

(ii) of this paragraph. 

(A) For intermittent bleed natural gas 

pneumatic devices that are subject to 

monitoring requirements in part 60, 

subpart OOOOb of this chapter or an 

approved state plan or Federal plan in 

part 62 of this chapter, as applicable, 

you must use the methods specified in 

the applicable standard. 

(B) For intermittent bleed natural gas 

pneumatic devices that are not subject 

to monitoring requirements in part 60, 

subpart OOOOb of this chapter or an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter and that you elect to 

monitor, you must use the methods 

specified in part 60, subpart OOOOb of 

this chapter. 

(ii) You must conduct at least one 

complete pneumatic device monitoring 

survey in a calendar year. If you 

conduct multiple complete pneumatic 

device monitoring surveys in a calendar 

year, you must use the results from each 

complete pneumatic device monitoring 

survey when calculating emissions 

using Equation W–1B. 

(iii) Calculate both CO2 and CH4 mass 

emissions using calculations in 

paragraph (v) of this section. 

* * * * * 

(c) Natural gas driven pneumatic 

pump venting. Calculate emissions from 

natural gas driven pneumatic pumps 

venting directly to the atmosphere as 

specified in paragraphs (c)(1) and (2) of 

this section. Calculate emissions from 

natural gas driven pneumatic pumps 

routed to flares, combustion, or vapor 

recovery systems as specified in 

paragraph (c)(3) of this section. You do 

not have to calculate emissions from 

natural gas driven pneumatic pumps 

covered in paragraph (e) of this section 

under this paragraph (c). 

(1) Calculate CH4 and CO2 volumetric 

emissions from natural gas driven 

pneumatic pump venting using 

Equation W–2 of this section. 

Where: 

Es,i = Annual total volumetric GHG emissions 

at standard conditions in standard cubic 

feet per year from all natural gas driven 

pneumatic pump venting, for GHGi. 

Count = Total number of natural gas driven 

pneumatic pumps that vented directly to 

the atmosphere. 

EF = Population emission factors for natural 

gas driven pneumatic pumps (in 

standard cubic feet per hour per pump) 

listed in Table W–1A of this subpart for 

onshore petroleum and natural gas 

production and onshore petroleum and 

natural gas gathering and boosting 

facilities. 

GHGi = Concentration of GHGi, CH4, or CO2, 

in produced natural gas as defined in 

paragraph (u)(2)(i) of this section. 

T = Average estimated number of hours in 

the operating year the pumps that vented 

directly to the atmosphere were in 

service (i.e., supplied with natural gas) 

using engineering estimates based on 

best available data. Default is 8,760 

hours for pumps that only vented 

directly to the atmosphere. 

(2) Calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculations in paragraph (v) of 

this section. 

(3) Calculate emissions from natural 

gas driven pneumatic pumps routed to 

flares, combustion, or vapor recovery 

systems as specified in paragraph 

(c)(3)(i) or (ii) of this section, as 

applicable. If a pump was vented 

directly to the atmosphere for part of the 

year and routed to a flare, combustion, 

or vapor recovery system during another 

part of the year, then calculate 

emissions from the time the pump vents 

directly to the atmosphere as specified 

in paragraphs (c)(1) and (2) of this 

section and calculate emissions from the 

time the pump was routed to a flare or 

combustion as specified in paragraphs 

(c)(3)(i) and (ii) of this section, as 

applicable. For emissions that are 

collected in a vapor recovery system 

that is not routed to combustion, 

paragraphs (c)(1) and (2) and (c)(3)(i) 

and (ii) do not apply and no emissions 

calculations are required. 

(i) If any natural gas driven pneumatic 

pumps were routed to a flare, you must 

calculate CH4, CO2, and N2O emissions 

for the flare stack as specified in 

paragraph (n) of this section and report 

emissions from the flare as specified in 

§ 98.236(n), without subtracting 

emissions attributable to natural gas 

driven pneumatic pumps from the flare. 

(ii) If emissions from any natural gas 

driven pneumatic pumps were routed to 

combustion, you must calculate 

emissions for the combustion 

equipment as specified in paragraph (z) 

of this section and report emissions 

from the combustion equipment as 

specified in § 98.236(z). 

(d) Acid gas removal (AGR) vents. For 

AGR vents (including processes such as 

amine, membrane, molecular sieve or 

other absorbents and adsorbents), 

calculate emissions for CO2 only (not 

CH4) vented directly to the atmosphere 

or emitted through an engine (e.g., 

permeate from a membrane or deadsorbed gas from a pressure swing 

adsorber used as fuel supplement), or 

sulfur recovery plant, using any of the 

calculation methods described in 


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paragraphs (d)(1) through (4) of this 

section, and also comply with 

paragraphs (d)(5) through (11), as 

applicable. For AGR emissions that are 

routed to a flare, calculate the flared 

emissions as specified in paragraph 

(d)(12) of this section. 

* * * * * 

(4) * * * 

(vi) Solvent type, pressure, 

temperature, circulation rate, and 

composition. 

* * * * * 

(12) For AGR vents routed to a flare, 

calculate CO2 emissions from the AGR 

as specified in paragraph (d)(12)(i) or (ii) 

of this section, as applicable. 

(i) For emissions from an AGR unit 

that are routed to a dedicated flare, or 

if the emissions from the AGR unit are 

comingled with emissions from any 

other source types for routing to a flare 

and you do not continuously measure 

either flow or composition of the 

comingled gas stream, then calculate 

CO2 emissions from the AGR using a 

method specified in paragraph (d)(1) 

through (4) of this section, as applicable. 

You must also incorporate your AGR 

data into the parameters Vs and XCO2 in 

Equation W–20 to account for the AGR 

portion of the total flared CO2 emissions 

for all miscellaneous flared sources as 

described in paragraphs (n)(1) and (2) of 

this section. 

(ii) For emissions from an AGR unit 

that are comingled with emissions from 

any other source types for routing to a 

flare and you continuously measure 

flow and/or composition of the 

comingled gas stream, then calculate 

total emissions from all miscellaneous 

flared sources (which includes AGRs) 

for the flare(s) to which the AGR 

emissions are routed using the 

procedures specified in paragraphs 

(n)(1) through (8) of this section. Use 

site-specific engineering estimates based 

on best available data to calculate the 

portion of the total flared CO2 emissions 

from the miscellaneous flared sources 

that entered the flare from the AGR. 

Report the calculated portion of the total 

flared CO2 emissions that entered the 

flare from the AGR as CO2 emissions 

from the AGR as specified in 

§ 98.236(d)(1)(v). Subtract this amount 

of CO2 from the total flared CO2 and 

report the remainder as CO2 from 

miscellaneous flared sources as 

specified in § 98.236(n)(1)(xi). 

(e) Dehydrator vents. For dehydrator 

vents, calculate annual CH4 and CO2

emissions using the applicable 

calculation methods described in 

paragraphs (e)(1) through (5) of this 

section. If emissions from dehydrator 

vents are routed to a vapor recovery 

system, you must adjust the emissions 

downward according to paragraph (e)(4) 

of this section. If emissions from 

dehydrator vents are routed to a flare or 

regenerator firebox/fire tubes, you must 

calculate CH4, CO2, and N2O annual 

emissions as specified in paragraph 

(e)(5) of this section. 

(1) Calculation Method 1. Calculate 

annual mass emissions from glycol 

dehydrators that have an annual average 

of daily natural gas throughput that is 

greater than or equal to 0.4 million 

standard cubic feet per day by using a 

software program, such as AspenTech 

HYSYS® or GRI–GLYCalcTM, that uses 

the Peng-Robinson equation of state to 

calculate the equilibrium coefficient, 

speciates CH4 and CO2 emissions from 

dehydrators, and has provisions to 

include regenerator control devices, a 

separator flash tank, stripping gas, and 

a gas injection pump or gas assist pump. 

Emissions must be modeled from both 

the still vent and, if applicable, the flash 

tank vent. The following parameters 

must be determined by engineering 

estimate based on best available data 

and must be used at a minimum to 

characterize emissions from 

dehydrators: 

* * * * * 

(x) Wet natural gas temperature and 

pressure at the absorber inlet. 

* * * * * 

(2) Calculation Method 2. Calculate 

annual volumetric emissions from 

glycol dehydrators that have an annual 

average of daily natural gas throughput 

that is less than 0.4 million standard 

cubic feet per day using Equation W–5 

of this section, and then calculate the 

collective CH4 and CO2 mass emissions 

from the volumetric emissions using the 

procedures in paragraph (v) of this 

section: 

* * * * * 

Count = Total number of glycol dehydrators 

that have an annual average daily natural 

gas throughput that is greater than 0 

million standard cubic feet per day and 

less than 0.4 million standard cubic feet 

per day. 

* * * * * 

(4) If the dehydrator unit has vapor 

recovery, calculate annual emissions as 

specified in paragraphs (e)(4)(i) and (ii) 

of this section. 

(i) Adjust the emissions estimated in 

paragraphs (e)(1) and (2) of this section, 

as applicable, downward by the 

magnitude of emissions recovered using 

a vapor recovery system and by the 

amount of emissions routed to flares or 

regenerator firebox/fire tubes as 

determined by engineering estimate 

based on best available data. Report 

unrecovered emissions that are not 

routed to flares or regenerator fireboxes/ 

fire tubes as emissions vented directly 

to the atmosphere. 

(ii) If unrecovered emissions from the 

dehydrator are routed to flares or 

regenerator fireboxes/fire tubes, use the 

calculation method of flare stacks in 

paragraph (n) of this section to 

determine dehydrator vent emissions 

from the flare or regenerator combustion 

gas vent. Use the volume routed to the 

flares or regenerator fireboxes/fire tubes 

and the dehydrator vent gas 

composition as determined using either 

engineering estimates based on best 

available data or the procedures 

specified in paragraph (u)(2) of this 

section, as applicable. Report 

unrecovered emissions that are routed 

to flares or regenerator fireboxes/fire 

tubes as flared emissions from 

dehydrators. 

(5) If any dehydrator vent streams are 

routed to a flare or regenerator firebox/ 

fire tubes, calculate emissions from 

these devices attributable to dehydrators 

as specified in paragraphs (e)(5)(i) 

through (v) of this section. If you 

operate a CEMS to monitor the 

emissions from the flare in accordance 

with paragraph (n)(8) of this section, 

calculate emissions as specified in 

paragraph (e)(5)(v) of this section 

instead of the provisions of paragraphs 

(e)(5)(i) through (iv) of this section. 

(i) Determine the volume of gas from 

the dehydrator(s) to each flare using any 

of the methods specified in paragraph 

(e)(5)(i)(A) or (B) of this section. You are 

not required to use the same method for 

all dehydrator streams. 

(A) Use the vented volume as 

determined in paragraphs (e)(1) through 

(4) of this section. 

(B) Measure the flow from the 

dehydrator(s) to the flare or regenerator 

firebox/fire tubes using a continuous 

flow measurement device. If the 

measured volume is in a manifold that 

combines flow from multiple 

dehydrators or from dehydrators and 

other sources, use engineering 

calculations based on process 

knowledge and best available data to 

estimate the portion(s) of the total flow 

(in scf) from each large dehydrator or 

from all small dehydrators combined. 

(ii) Except as specified in paragraph 

(e)(5)(iii) of this section, determine 

composition of the gas from the 

dehydrator(s) to each flare or 

regenerator firebox/fire tubes using any 

of the methods specified in paragraphs 

(e)(5)(ii)(A) through (C) of this section. 

You are not required to use the same 

method for all dehydrator streams. 

(A) Use the gas composition as 

determined in paragraphs (e)(1) through 

(4) of this section. 


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(B) Measure the composition of the 

gas from the dehydrator(s) to the flare or 

regenerator firebox/fire tubes using a 

continuous composition analyzer. If the 

measured composition is in a manifold 

that combines streams only from 

multiple dehydrators, assume the 

measured composition applies to all 

dehydrators that route gas through the 

manifold. 

(C) Measure the composition of the 

total gas to the flare or regenerator 

firebox/fire tubes using a continuous 

composition analyzer. If the measured 

composition is in a manifold that 

combines flow from dehydrators and 

other sources, use engineering 

calculations based on available 

sampling data for other sources, process 

knowledge, and best available data to 

estimate the composition of the flow 

from each large dehydrator or from all 

small dehydrators combined. 

(iii) If you continuously measure flow 

in accordance with paragraph (e)(5)(i)(B) 

of this section and/or continuously 

measure gas composition in accordance 

with paragraph (e)(5)(ii)(B) or (C) of this 

section, then those measured data must 

be used, either directly or after 

disaggregating to individual sources, to 

calculate dehydrator emissions from 

flares or regenerator firebox/fire tubes. 

(iv) Use the calculation method of 

flare stacks in paragraphs (n)(3) through 

(7) of this section to calculate annual 

dehydrator emissions from flares or 

regenerator firebox/fire tubes. 

(v) If you monitor the flare with 

CEMS, use the calculation procedures in 

paragraph (n)(8) of this section. If the 

flare receives gas from multiple 

dehydrators or from both dehydrators 

and other sources, then use engineering 

calculations based on process 

knowledge and best available data to 

estimate the portions of the total CO2

emissions measured by the CEMS that 

are from each large dehydrator and from 

all small dehydrators combined. 

* * * * * 

(g) * * * 

(4) If any streams from well 

completions and workovers with 

hydraulic fracturing are flared, calculate 

annual emissions as specified in 

paragraphs (g)(4)(i) through (v) of this 

section. If you operate a CEMS to 

monitor the emissions from the flare in 

accordance with paragraph (n)(8) of this 

section, calculate emissions as specified 

in paragraph (g)(4)(v) of this section 

instead of the provisions of paragraphs 

(g)(4)(i) through (iv) of this section. 

(i) Determine the volume of gas from 

well completions and workovers with 

hydraulic fracturing routed to each flare 

using any of the methods specified in 

paragraph (g)(4)(i)(A) or (B) of this 

section. You are not required to use the 

same method for all streams. 

(A) Use the volume from gas venting 

to the atmosphere during well 

completions and workovers with 

hydraulic fracturing as determined in 

paragraph (g) of this section. Subtract 

the estimated amount vented to the 

atmosphere, if any, from this total 

volume. 

(B) Measure the flow from well 

completions and workovers with 

hydraulic fracturing to the flare using a 

continuous flow measurement device. If 

the measured volume is in a manifold 

that combines flow from well 

completions and workovers with 

hydraulic fracturing and other sources, 

use engineering calculations based on 

process knowledge and best available 

data to estimate the portion(s) of the 

total flow (in scf) from well completions 

and workovers with hydraulic 

fracturing. 

(ii) Except as specified in paragraph 

(g)(4)(iii) of this section, determine 

composition of the gas from well 

completions and workovers with 

hydraulic fracturing to each flare using 

any of the methods specified in 

paragraphs (g)(4)(ii)(A) through (C) of 

this section. You are not required to use 

the same method for all streams. 

(A) Use the gas composition as 

determined in paragraph (g)(3) of this 

section. 

(B) Measure the composition of the 

gas from well completions and 

workovers with hydraulic fracturing to 

the flare using a continuous 

composition analyzer. If the measured 

composition is in a manifold that 

combines streams only from well 

completions and workovers with 

hydraulic fracturing, assume the 

measured composition applies to all 

completions and workovers with 

hydraulic fracturing that route gas 

through the manifold. 

(C) Measure the composition of the 

total gas to the flare using a continuous 

composition analyzer. If the measured 

composition is in a manifold that 

combines flow from well completions 

and workovers with hydraulic fracturing 

and other sources, use engineering 

calculations based on available 

sampling data for other sources, process 

knowledge, and best available data to 

estimate the composition of the flow 

from each well completions and 

workovers with hydraulic fracturing. 

(iii) If you continuously measure flow 

in accordance with paragraph (g)(4)(i)(B) 

of this section and/or continuously 

measure gas composition in accordance 

with paragraph (g)(4)(ii)(B) or (C) of this 

section, then those measured data must 

be used, either directly or after 

disaggregating to individual sources, to 

calculate well completion and workover 

from hydraulic fracturing emissions 

from flares. 

(iv) Use the calculation method of 

flare stacks in paragraphs (n)(3) through 

(7) of this section to calculate annual 

emissions for the portion of gas flared 

during well completions and workovers 

using hydraulic fracturing. 

(v) If you monitor the flare with 

CEMS, use the calculation procedures in 

paragraph (n)(8) of this section. If the 

flare receives gas from multiple well 

completions and workovers with 

hydraulic fracturing or from both well 

completions and workovers with 

hydraulic fracturing and other sources, 

then use engineering calculations based 

on process knowledge and best available 

data to estimate the portions of the total 

CO2 emissions measured by the CEMS 

that are from well completions and 

workovers with hydraulic fracturing. 

(h) * * * 

(2) If any streams from gas well 

completions and workovers without 

hydraulic fracturing are flared, calculate 

annual emissions of CH4, CO2, and N2O 

as specified in paragraphs (h)(2)(i) 

through (v) of this section. If you 

operate a CEMS to monitor the 

emissions from the flare in accordance 

with paragraph (n)(8) of this section, 

calculate emissions as specified in 

paragraph (h)(2)(v) of this section 

instead of the provisions of paragraphs 

(h)(2)(i) through (iv) of this section. 

(i) Determine the volume of gas from 

well completions and workovers 

without hydraulic fracturing routed to 

each flare using any of the methods 

specified in paragraph (h)(2)(i)(A) or (B) 

of this section. You are not required to 

use the same method for all streams. 

(A) Use the gas well venting volume 

during well completions and workovers 

without hydraulic fracturing that are 

flared as determined using the methods 

specified in paragraphs (h) and (h)(1) of 

this section. 

(B) Measure the flow from well 

completions and workovers without 

hydraulic fracturing to the flare using a 

continuous flow measurement device. If 

the measured volume is in a manifold 

that combines flow from well 

completions and workovers without 

hydraulic fracturing and other sources, 

use engineering calculations based on 

process knowledge and best available 

data to estimate the portion(s) of the 

total flow (in scf) from well completions 

and workovers without hydraulic 

fracturing. 

(ii) Determine composition of the gas 

from well completions and workovers 

without hydraulic fracturing to each 


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flare using any of the methods specified 

in paragraphs (h)(2)(ii)(A) through (C) of 

this section. You are not required to use 

the same method for all streams. 

(A) Use the gas composition as 

determined in paragraphs (h) 

introductory text and (h)(1) of this 

section. 

(B) Measure the composition of the 

gas from well completions and 

workovers without hydraulic fracturing 

to the flare using a continuous 

composition analyzer. If the measured 

composition is in a manifold that 

combines streams only from well 

completions and workovers without 

hydraulic fracturing, assume the 

measured composition applies to all 

completions and workovers without 

hydraulic fracturing that route gas 

through the manifold. 

(C) Measure the composition of the 

total gas to the flare using a continuous 

composition analyzer. If the measured 

composition is in a manifold that 

combines flow from well completions 

and workovers without hydraulic 

fracturing and other sources, use 

engineering calculations based on 

available sampling data for other 

sources, process knowledge, and best 

available data to estimate the 

composition of the flow from each well 

completions and workovers without 

hydraulic fracturing. 

(iii) If you continuously measure flow 

in accordance with paragraph 

(h)(2)(i)(B) of this section and/or 

continuously measure gas composition 

in accordance with paragraph 

(h)(2)(ii)(B) or (C) of this section, then 

those measured data must be used, 

either directly or after disaggregating to 

individual sources, to calculate well 

completion and workover from 

hydraulic fracturing emissions from 

flares. 

(iv) Use the calculation method of 

flare stacks in paragraphs (n)(3) through 

(7) of this section to calculate annual 

emissions from the flare for gas well 

venting to a flare during completions 

and workovers without hydraulic 

fracturing. 

(v) If you monitor the flare with 

CEMS, use the calculation procedures in 

paragraph (n)(8) of this section. If the 

flare receives gas from multiple well 

completions and workovers without 

hydraulic fracturing or from both well 

completions and workovers without 

hydraulic fracturing and other sources, 

then use engineering calculations based 

on process knowledge and best available 

data to estimate the portions of the total 

CO2 emissions measured by the CEMS 

that are from well completions and 

workovers without hydraulic fracturing. 

(i) Blowdown vent stacks. Calculate 

CO2 and CH4 blowdown vent stack 

emissions from the depressurization of 

equipment to reduce system pressure for 

planned or emergency shutdowns 

resulting from human intervention or to 

take equipment out of service for 

maintenance as specified in either 

paragraph (i)(2) or (3) of this section. 

You may use the method in paragraph 

(i)(2) of this section for some blowdown 

vent stacks at your facility and the 

method in paragraph (i)(3) of this 

section for other blowdown vent stacks 

at your facility. Equipment with a 

unique physical volume of less than 50 

cubic feet as determined in paragraph 

(i)(1) of this section are not subject to 

the requirements in paragraphs (i)(2) 

through (4) of this section. The 

requirements in this paragraph (i) do not 

apply to blowdown vent stack emissions 

from depressurizing to a flare, overpressure relief, operating pressure 

control venting, and blowdown of nonGHG gases. 

* * * * * 

(2) Method for determining emissions 

from blowdown vent stacks according to 

equipment or event type. If you elect to 

determine emissions according to each 

equipment or event type, using unique 

physical volumes as calculated in 

paragraph (i)(1) of this section, you must 

calculate emissions as specified in 

paragraph (i)(2)(i) of this section and 

either paragraph (i)(2)(ii) of this section 

or, if applicable, paragraph (i)(2)(iii) of 

this section for each equipment or event 

type. Categorize equipment and event 

types for each industry segment as 

specified in paragraph (i)(2)(iv) of this 

section. 

(i) * * * 

Ta = Temperature at actual conditions in the 

unique physical volume (°F). For 

emergency blowdowns at onshore 

petroleum and natural gas gathering and 

boosting facilities and onshore natural 

gas transmission pipeline facilities, 

engineering estimates based on best 

available information may be used to 

determine the temperature. 

* * * * * 

Pa = Absolute pressure at actual conditions 

in the unique physical volume (psia). For 

emergency blowdowns at onshore 

petroleum and natural gas gathering and 

boosting facilities and onshore natural 

gas transmission pipeline facilities, 

engineering estimates based on best 

available information may be used to 

determine the pressure. 

* * * * * 

Ta,p = Temperature at actual conditions in the 

unique physical volume (°F) for each 

blowdown ‘‘p’’. For emergency 

blowdowns at onshore petroleum and 

natural gas gathering and boosting 

facilities and onshore natural gas 

transmission pipeline facilities, 

engineering estimates based on best 

available information may be used to 

determine the temperature. 

* * * * * 

Pa,b,p = Absolute pressure at actual conditions 

in the unique physical volume (psia) at 

the beginning of the blowdown ‘‘p’’. For 

emergency blowdowns at onshore 

petroleum and natural gas gathering and 

boosting facilities and onshore natural 

gas transmission pipeline facilities, 

engineering estimates based on best 

available information may be used to 

determine the pressure at the beginning 

of the blowdown. 

Pa,e,p = Absolute pressure at actual conditions 

in the unique physical volume (psia) at 

the end of the blowdown ‘‘p’’; 0 if 

blowdown volume is purged using nonGHG gases. For emergency blowdowns at 

onshore petroleum and natural gas 

gathering and boosting facilities and 

onshore natural gas transmission 

pipeline facilities, engineering estimates 

based on best available information may 

be used to determine the pressure at the 

end of the blowdown. 

* * * * * 

(iv) Categorize blowdown vent stack 

emission events as specified in 

paragraphs (i)(2)(iv)(A) and (B) of this 

section, as applicable. 

(A) For the onshore natural gas 

processing, transmission compression, 

LNG import and export equipment, and 

onshore petroleum and natural gas 

gathering and boosting industry 

segments, equipment or event types 

must be grouped into the following 

seven categories: Facility piping (i.e., 

physical volumes associated with 

piping for which the entire physical 

volume is located within the facility 

boundary), pipeline venting (i.e., 

physical volumes associated with 

pipelines for which a portion of the 

physical volume is located outside the 

facility boundary and the remainder, 

including the blowdown vent stack, is 

located within the facility boundary), 

compressors, scrubbers/strainers, pig 

launchers and receivers, emergency 

shutdowns (this category includes 

emergency shutdown blowdown 

emissions regardless of equipment 

type), and all other equipment with a 

physical volume greater than or equal to 

50 cubic feet. If a blowdown event 

resulted in emissions from multiple 

equipment types and the emissions 

cannot be apportioned to the different 

equipment types, then categorize the 

blowdown event as the equipment type 

that represented the largest portion of 

the emissions for the blowdown event. 

(B) For the onshore natural gas 

transmission pipeline segment, pipeline 


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segments or event types must be 

grouped into the following eight 

categories: Pipeline integrity work (e.g., 

the preparation work of modifying 

facilities, ongoing assessments, 

maintenance or mitigation), traditional 

operations or pipeline maintenance, 

equipment replacement or repair (e.g., 

valves), pipe abandonment, new 

construction or modification of 

pipelines including commissioning and 

change of service, operational 

precaution during activities (e.g. 

excavation near pipelines), emergency 

shutdowns including pipeline incidents 

as defined in 49 CFR 191.3, and all 

other pipeline segments with a physical 

volume greater than or equal to 50 cubic 

feet. If a blowdown event resulted in 

emissions from multiple categories and 

the emissions cannot be apportioned to 

the different categories, then categorize 

the blowdown event in the category that 

represented the largest portion of the 

emissions for the blowdown event. 

* * * * * 

(j) Onshore production and onshore 

petroleum and natural gas gathering 

and boosting storage tanks. Calculate 

CH4, CO2, and N2O (when flared) 

emissions from atmospheric pressure 

fixed roof storage tanks receiving 

hydrocarbon produced liquids from 

onshore petroleum and natural gas 

production facilities and onshore 

petroleum and natural gas gathering and 

boosting facilities (including stationary 

liquid storage not owned or operated by 

the reporter), as specified in this 

paragraph (j). For gas-liquid separators 

or onshore petroleum and natural gas 

gathering and boosting non-separator 

equipment (e.g., stabilizers, slug 

catchers) with annual average daily 

throughput of hydrocarbon liquids 

greater than or equal to 10 barrels per 

day, calculate annual CH4 and CO2

using Calculation Method 1 or 2 as 

specified in paragraphs (j)(1) and (2) of 

this section. For wells flowing directly 

to atmospheric storage tanks without 

passing through a separator with 

throughput greater than or equal to 10 

barrels per day, calculate annual CH4

and CO2 emissions using Calculation 

Method 2 as specified in paragraph (j)(2) 

of this section. For hydrocarbon liquids 

flowing to gas-liquid separators or nonseparator equipment or directly to 

atmospheric storage tanks with 

throughput less than 10 barrels per day, 

use Calculation Method 3 as specified in 

paragraph (j)(3) of this section. If you 

use Calculation Method 1 or Calculation 

Method 2 for separators, you must also 

calculate emissions that may have 

occurred due to dump valves not 

closing properly using the method 

specified in paragraph (j)(6) of this 

section. If emissions from atmospheric 

pressure fixed roof storage tanks are 

routed to a vapor recovery system, you 

must adjust the emissions downward 

according to paragraph (j)(4) of this 

section. If emissions from atmospheric 

pressure fixed roof storage tanks are 

routed to a flare, you must calculate 

CH4, CO2, and N2O annual emissions as 

specified in paragraph (j)(5) of this 

section. 

(1) Calculation Method 1. Calculate 

annual CH4 and CO2 emissions from 

onshore production storage tanks and 

onshore petroleum and natural gas 

gathering and boosting storage tanks 

using operating conditions in the last 

gas-liquid separator or non-separator 

equipment before liquid transfer to 

storage tanks. Calculate flashing 

emissions with a software program, 

such as AspenTech HYSYS® or API 

4697 E&P Tank, that uses the PengRobinson equation of state, models 

flashing emissions, and speciates CH4

and CO2 emissions that will result when 

the hydrocarbon liquids from the 

separator or non-separator equipment 

enter an atmospheric pressure storage 

tank. The following parameters must be 

determined for typical operating 

conditions over the year by engineering 

estimate and process knowledge based 

on best available data, and must be used 

at a minimum to characterize emissions 

from liquid transferred to tanks: 

* * * * * 

(iii) Sales oil or stabilized 

hydrocarbon liquids API gravity. 

(iv) Sales oil or stabilized 

hydrocarbon liquids production rate. 

* * * * * 

(vii) Separator or non-separator 

equipment hydrocarbon liquids 

composition and Reid vapor pressure. If 

this data is not available, determine 

these parameters by using one of the 

methods described in paragraphs 

(j)(1)(vii)(A) through (C) of this section. 

(A) If separator or non-separator 

equipment hydrocarbon liquid 

composition and Reid vapor pressure 

default data are provided with the 

software program, select the default 

values that most closely match your 

separator or non-separator equipment 

pressure first, and API gravity 

secondarily. 

(B) If separator or non-separator 

equipment hydrocarbon liquids 

composition and Reid vapor pressure 

data are available through your previous 

analysis, select the latest available 

analysis that is representative of 

produced crude oil or condensate from 

the sub-basin category for onshore 

petroleum and natural gas production or 

from the county for onshore petroleum 

and natural gas gathering and boosting. 

(C) Analyze a representative sample of 

separator or non-separator equipment 

hydrocarbon liquids in each sub-basin 

category for onshore petroleum and 

natural gas production or each county 

for onshore petroleum and natural gas 

gathering and boosting for hydrocarbon 

liquids composition and Reid vapor 

pressure using an appropriate standard 

method published by a consensus-based 

standards organization. 

(2) Calculation Method 2. Calculate 

annual CH4 and COCO2 emissions using 

the methods in paragraph (j)(2)(i) of this 

section for gas-liquid separators with 

annual average daily throughput of 

hydrocarbon liquids greater than or 

equal to 10 barrels per day. Calculate 

annual CH4 and COCO2 emissions using 

the methods in paragraph (j)(2)(ii) of 

this section for wells with annual 

average daily hydrocarbon liquids 

production greater than or equal to 10 

barrels per day that flow directly to 

atmospheric storage tanks in onshore 

petroleum and natural gas production 

and onshore petroleum and natural gas 

gathering and boosting (if applicable). 

Calculate annual CH4 and COCO2

emissions using the methods in 

paragraph (j)(2)(iii) of this section for 

non-separator equipment with annual 

average daily hydrocarbon liquids 

throughput greater than or equal to 10 

barrels per day that flow directly to 

atmospheric storage tanks in onshore 

petroleum and natural gas gathering and 

boosting. 

(i) Flow to storage tank after passing 

through a separator. Assume that all of 

the CH4 and COCO2 in solution at 

separator temperature and pressure is 

emitted from hydrocarbon liquids sent 

to storage tanks. You may use an 

appropriate standard method published 

by a consensus-based standards 

organization if such a method exists or 

you may use an industry standard 

practice as described in § 98.234(b) to 

sample and analyze separator 

hydrocarbon liquids composition at 

separator pressure and temperature. 

(ii) Flow to storage tank direct from 

wells. Calculate CH4 and COCO2

emissions using either of the methods in 

paragraph (j)(2)(ii)(A) or (B) of this 

section. 

(A) If well production hydrocarbon 

liquids and gas compositions are 

available through a previous analysis, 

select the latest available analysis that is 

representative of produced hydrocarbon 

liquids and gas from the sub-basin 

category and assume all of the CH4 and 

CO2 in both hydrocarbon liquids and 

gas are emitted from the tank. 


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(B) If well production hydrocarbon 

liquids and gas compositions are not 

available, use default hydrocarbon 

liquids and gas compositions in 

software programs, such as API 4697 

E&P Tank, that most closely match the 

well production gas/oil ratio and API 

gravity and assume all of the CH4 and 

CO2 in both hydrocarbon liquids and 

gas are emitted from the tank. 

(iii) Flow to storage tank direct from 

non-separator equipment. Calculate CH4 

and CO2 emissions using either of the 

methods in paragraph (j)(2)(iii)(A) or (B) 

of this section. 

(A) If other non-separator equipment 

hydrocarbon liquids and gas 

compositions are available through a 

previous analysis, select the latest 

available analysis that is representative 

of hydrocarbon liquids and gas from 

non-separator equipment in the same 

county and assume all of the CH4 and 

CO2 in both hydrocarbon liquids and 

gas are emitted from the tank. 

(B) If non-separator equipment 

hydrocarbon liquids and gas 

compositions are not available, use 

default hydrocarbon liquids and gas 

compositions in software programs, 

such as API 4697 E&P Tank, that most 

closely match the non-separator 

equipment gas/liquid ratio and API 

gravity and assume all of the CH4 and 

CO2 in both hydrocarbon liquids and 

gas are emitted from the tank. 

(3) * * * 

Count = Total number of separators, wells, or 

non-separator equipment with annual 

average daily throughput less than 10 

barrels per day. Count only separators, 

wells, or non-separator equipment that 

feed hydrocarbon liquids directly to the 

storage tank. 

* * * * * 

(4) If the storage tank receiving your 

hydrocarbon liquids has a vapor 

recovery system, calculate annual 

emissions from storage tanks as 

specified in paragraphs (j)(4)(i) and (ii) 

of this section. 

(i) Using engineering estimates based 

on best available data, determine the 

portion of the total emissions estimated 

in paragraphs (j)(1) through (3) of this 

section that is recovered using a vapor 

recovery system. You must take into 

account periods with reduced capture 

efficiency of the vapor recovery system 

(e.g., when a thief hatch is open or not 

properly seated) when calculating 

emissions recovered. 

(ii) Determine total emissions not 

recovered by a vapor recovery system as 

specified in paragraphs (j)(4)(ii)(A) and 

(B) of this section. 

(A) Adjust the emissions estimated in 

paragraphs (j)(1) through (3) of this 

section downward by the magnitude of 

emissions recovered using a vapor 

recovery system and by the amount of 

emissions routed to flares. Unrecovered 

emissions may include, but are not 

limited to, emissions during periods 

when the vapor recovery system is not 

operating, losses from the tank when the 

vapor recovery system is not operating 

and the tank is connected to a flare, and 

losses from the tank during periods 

when the vapor recovery system is 

operating. These losses may include, but 

are not limited to, emissions due to 

open or unseated thief hatches. Report 

unrecovered emissions that are not 

routed to flares as emissions vented 

directly to the atmosphere. 

(B) If unrecovered emissions from 

atmospheric tanks are routed to flares, 

determine the volume of gas routed to 

flares, calculate annual emissions from 

flares as specified in paragraphs (j)(5)(i) 

through (iii) of this section, and report 

as flared emissions from atmospheric 

tanks. 

(5) If the storage tank receiving your 

hydrocarbon liquids has a flare(s), 

calculate annual flared emissions from 

storage tanks as specified in paragraphs 

(j)(5)(i) through (v) of this section and 

calculate emissions vented directly to 

the atmosphere as specified in 

paragraph (j)(5)(vi) of this section. For 

atmospheric tanks with emissions 

calculated using Calculation Method 3 

in paragraph (j)(3) of this section, this 

paragraph (j)(5) only applies when at 

least half of the hydrocarbon liquids 

flowing to gas-liquid separators or nonseparator equipment or directly to 

atmospheric storage tanks are directed 

to atmospheric tanks that used flares to 

control emissions. If you operate a 

CEMS to monitor the emissions from the 

flare in accordance with paragraph 

(n)(8) of this section, calculate 

emissions as specified in paragraph 

(j)(5)(v) of this section instead of the 

provisions of paragraphs (j)(5)(i) through 

(iv) of this section. 

(i) Estimate the volume routed to the 

flare using any of the methods specified 

in paragraph (j)(5)(i)(A) or (B) of this 

section. You are not required to use the 

same method for all storage tanks. 

(A) If unrecovered emissions from the 

storage tank are calculated in 

accordance with paragraph (j)(4) of this 

section, then determine the volume of 

the unrecovered emissions routed to 

flares based on best available data. If no 

emissions from the storage tank are 

routed to vapor recovery, then use the 

storage tank emissions volume as 

determined in paragraphs (j)(1) through 

(3) of this section, except that you must 

also adjust this total volume of 

emissions downward by the estimated 

portion of the total volume that is not 

routed to the flare (e.g., when the flare 

is bypassed or when a thief hatch is 

open or not properly seated). Estimate 

the volume of the emissions not routed 

to flares based on best available data. 

(B) Measure the flow from the storage 

tank(s) to the flare using a continuous 

flow measurement device. If the 

measured volume is in a manifold that 

combines flow from storage tanks and 

other sources, use engineering 

calculations based on process 

knowledge and best available data to 

estimate the portion(s) of the total flow 

(in scf) from each storage tank. 

(ii) Except as specified in paragraph 

(j)(5)(iii) of this section, determine the 

composition of the gas from the storage 

tanks routed to the flare using any of the 

methods specified in paragraphs 

(j)(5)(ii)(A) through (C) of this section. 

You are not required to use the same 

method for all storage tanks. 

(A) If you use Calculation Method 1 

or Calculation Method 2, use your gas 

composition as determined in 

paragraphs (j)(1) and (2) of this section. 

If you use Calculation Method 3 in 

paragraph (j)(3) of this section, 

determine the gas composition using 

either engineering estimates based on 

best available data or the procedures 

specified in paragraph (u)(2)(i) of this 

section. 

(B) Measure the composition of the 

gas from the storage tanks to the flare 

using a continuous gas composition 

analyzer. If the measured composition is 

in a manifold that combines streams 

only from multiple storage tanks, 

assume the measured composition 

applies to all storage tanks that route gas 

through the manifold. 

(C) Measure the composition of the 

total gas to the flare using a continuous 

composition analyzer. If the measured 

composition is in a manifold that 

combines flow from storage tanks and 

other sources, use engineering 

calculations based on available 

sampling data for other sources, process 

knowledge, and best available data to 

estimate the composition of the flow 

from storage tanks. 

(iii) If you continuously measure flow 

in accordance with paragraph (j)(5)(i)(B) 

of this section and/or continuously 

measure gas composition in accordance 

with paragraph (j)(5)(ii)(B) or (C) of this 

section, then those measured data must 

be used, either directly or after 

disaggregating to individual sources, to 

calculate storage tank emissions from 

flares. 

(iv) Use the calculation method of 

flare stacks in paragraphs (n)(3) through 

(7) of this section with the volume and 

composition determined according to 

paragraphs (j)(5)(i) and (ii) of this 


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section to determine storage tank 

emissions from the flare. 

(v) If you monitor the flare with 

CEMS, use the calculation procedures in 

paragraph (n)(8) of this section. If the 

flare receives gas from both storage 

tanks and other sources, then use 

engineering calculations based on 

process knowledge and best available 

data to estimate the portions of the total 

CO2 emissions measured by the CEMS 

that are from storage tanks. 

(vi) For storage tanks with no vapor 

recovery system, if the volume routed to 

the flare as determined in paragraph 

(j)(5)(i)(A) or (B) of this section is less 

than the total volume of emissions from 

the tank as estimated in paragraphs (j)(1) 

through (3) of this section, then use the 

volume not sent to the flare to calculate 

emissions of flash gas vented directly to 

the atmosphere from the storage tank. 

(6) If you use Calculation Method 1 or 

Calculation Method 2 in paragraph (j)(1) 

or (2) of this section, calculate emissions 

from occurrences of gas-liquid separator 

liquid dump valves not closing during 

the calendar year by using Equation W– 

16 of this section. 

Where: 

Es,i,dv = Annual volumetric GHG emissions 

(either CO2 or CH4) at standard 

conditions in cubic feet from storage 

tanks that resulted from the dump valve 

on the gas-liquid separator not closing 

properly. 

Es,i = Annual volumetric GHG emissions 

(either CO2 or CH4) as determined in 

paragraphs (j)(1) and (2) and, if 

applicable, (j)(4) and (5) of this section, 

in standard cubic feet per year, from 

storage tanks with dump valves on an 

associated gas-liquid separator that did 

not close properly. 

Tdv = Total time a dump valve is not closing 

properly in the calendar year in hours. 

Estimate Tdv based on maintenance, 

operations, or routine separator 

inspections that indicate the period of 

time when the valve was malfunctioning 

in open or partially open position. 

CFdv = Correction factor for tank emissions 

for time period Tdv is 2.87 for crude oil 

production. Correction factor for tank 

emissions for time period Tdv is 4.37 for 

gas condensate production. 

8,760 = Conversion to hourly emissions. 

* * * * * 

(k) * * * 

(5) If any transmission storage tanks 

are routed to flares, calculate emissions 

for the flare stack as specified in 

paragraph (n) of this section and report 

emissions from the flare as specified in 

§ 98.236(n), without subtracting 

emissions attributable to transmission 

tanks from the flare. If the volume to the 

flare is not continuously measured for 

the duration of time that flaring 

occurred, then conduct an annual leak 

measurement as specified in paragraph 

(k)(1)(ii) or (iv) of this section. If a leak 

is detected, quantify the leak in 

accordance with paragraph (k)(2)(i) or 

(ii) of this section and determine the 

time leaking as specified in paragraph 

(k)(3) of this section. Use these data 

when estimating total flow to the flare 

in accordance with paragraph (n)(1) of 

this section. 

(l) * * * 

(6) If any emissions from well testing 

are routed to a flare, calculate flared 

emissions from well testing as specified 

in paragraphs (l)(6)(i) through (v) of this 

section. If you operate a CEMS to 

monitor the emissions from the flare in 

accordance with paragraph (n)(8) of this 

section, calculate emissions as specified 

in paragraph (l)(6)(v) of this section 

instead of the provisions of paragraphs 

(l)(6)(i) through (iv) of this section. 

(i) Determine the volume of gas from 

well testing to each flare using any of 

the methods specified in paragraph 

(l)(6)(i)(A) or (B) of this section. You are 

not required to use the same method for 

all well testing. 

(A) Use the well testing emissions 

volume as determined in paragraphs 

(l)(1) through (4) of this section. 

(B) Measure the flow from well testing 

to the flare using a continuous flow 

measurement device. If the measured 

volume is in a manifold that combines 

flow from well testing and other 

sources, use engineering calculations 

based on process knowledge and best 

available data to estimate the portion(s) 

of the total flow (in scf) from well 

testing. 

(ii) Except as specified in paragraph 

(l)(6)(iii) of this section, determine 

composition of the gas from well testing 

to each flare using any of the methods 

specified in paragraphs (l)(6)(ii)(A) 

through (C) of this section. You are not 

required to use the same method for all 

well testing. 

(A) Use the gas composition as 

determined in paragraphs (l)(1) through 

(4) of this section. 

(B) Measure the composition of gas 

from well testing to the flare using a 

continuous composition analyzer. If the 

measured composition is in a manifold 

that combines streams only from testing 

of multiple wells, assume the measured 

composition applies to all well testing 

gas routed through the manifold. 

(C) Measure the composition of the 

total gas to the flare using a continuous 

composition analyzer. If the measured 

composition is in a manifold that 

combines flow from well testing and 

other sources, use engineering 

calculations based on available 

sampling data for other sources, process 

knowledge, and best available data to 

estimate the composition of the flow 

from well testing. 

(iii) If you continuously measure flow 

in accordance with paragraph (l)(6)(i)(B) 

of this section and/or continuously 

measure gas composition in accordance 

with paragraph (l)(6)(ii)(B) or (C) of this 

section, then those measured data must 

be used, either directly or after 

disaggregating to individual sources, to 

calculate well testing emissions from 

flares. 

(iv) Use the calculation method of 

flare stacks in paragraphs (n)(3) through 

(7) of this section to determine annual 

well testing emissions from the flare. 

(v) If you monitor the flare with 

CEMS, use the calculation procedures in 

paragraph (n)(8) of this section. If the 

flare receives gas from both well testing 

and other sources, then use engineering 

calculations based on process 

knowledge and best available data to 

estimate the portions of the total CO2

emissions measured by the CEMS that 

are from well testing. 

(m) * * * 

(3) Estimate venting emissions using 

Equation W–18 of this section. 

Alternatively, if you measure the flow to 

a vent using a continuous flow 

measurement device, you must use the 

measured flow volumes to calculate 

vented associated gas emissions. 

* * * * * 

Vp,q = Volume of oil produced, for well p in 

sub-basin q, in barrels in the calendar 

year only during time periods in which 

associated gas was vented or flared. 

SGp,q = Volume of associated gas sent to 

sales, for well p in sub-basin q, in 

standard cubic feet of gas in the calendar 

year only during time periods in which 

associated gas was vented or flared. 

* * * * * 

(5) Calculate flared associated natural 

gas emissions as specified in paragraphs 

(m)(5)(i) through (v) of this section. If 

you operate a CEMS to monitor the 

emissions from the flare in accordance 


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with paragraph (n)(8) of this section, 

calculate emissions as specified in 

paragraph (m)(5)(v) of this section 

instead of the provisions of paragraphs 

(m)(5)(i) through (iv) of this section. 

(i) Determine the volume of associated 

gas to each flare using any of the 

methods specified in paragraph 

(m)(5)(i)(A) or (B) of this section. You 

are not required to use the same method 

for all associated gas streams. 

(A) Use the associated natural gas 

volume as determined in paragraphs 

(m)(1) through (4) of this section. 

(B) Measure the flow of associated gas 

to the flare using a continuous flow 

measurement device. If the measured 

volume is in a manifold that combines 

flow from multiple associated gas 

streams or from associated gas streams 

and other sources, use engineering 

calculations based on process 

knowledge and best available data to 

estimate the portions of the total flow 

(in scf) that is associated gas. 

(ii) Except as specified in paragraph 

(m)(5)(iii) of this section, determine 

composition of the associated gas to 

each flare using any of the methods 

specified in paragraphs (m)(5)(ii)(A) 

through (C) of this section. You are not 

required to use the same method for all 

associated gas streams. 

(A) Use the associated gas 

composition as determined in 

paragraphs (m)(1) through (4) of this 

section. 

(B) Measure the composition of the 

associated gas to the flare using a 

continuous composition analyzer. If the 

measured composition is in a manifold 

that combines only associated gas 

streams, assume the measured 

composition applies to all associated gas 

that is routed through the manifold. 

(C) Measure the composition of the 

total gas to the flare using a continuous 

composition analyzer. If the measured 

composition is in a manifold that 

combines both associated gas and gas 

from other sources, use engineering 

calculations based on available 

sampling data for other sources, process 

knowledge, and best available data to 

estimate the composition of the 

associated gas in the combined stream. 

(iii) If you continuously measure flow 

in accordance with paragraph 

(m)(5)(i)(B) of this section and/or 

continuously measure gas composition 

in accordance with paragraph 

(m)(5)(ii)(B) or (C) of this section, then 

those measured data must be used, 

either directly or after disaggregating to 

individual sources, to calculate 

associated gas emissions from flares. 

(iv) Use the calculation method of 

flare stacks in paragraphs (n)(3) through 

(7) of this section to calculate annual 

associated gas emissions from flares. 

(v) If you monitor the flare with 

CEMS, use the calculation procedures in 

paragraph (n)(8) of this section. If the 

flare receives both associated gas and 

gas from other sources, then use 

engineering calculations based on 

process knowledge and best available 

data to estimate the portions of the total 

CO2 emissions measured by the CEMS 

that are from associated gas. 

(n) Flare stack emissions. As 

applicable for the industry segment, use 

the procedures in paragraphs (n)(3) 

through (9) of this section to calculate 

CO2, CH4, and N2O emissions per flare 

stack separately from dehydrators as 

specified in paragraph (e)(5) of this 

section, completions and workovers 

with hydraulic fracturing as specified in 

paragraph (g)(4) of this section, 

completions and workovers without 

hydraulic fracturing as specified in 

paragraph (h)(2) of this section, 

atmospheric tanks as specified in 

paragraph (j)(5) of this section, well 

testing as specified in paragraph (l)(6) of 

this section, and associated gas as 

specified in paragraph (m)(5) of this 

section. Also use the procedures 

specified in paragraphs (n)(1) through 

(9) of this section to calculate the 

collective emissions per flare stack from 

all miscellaneous flared sources (i.e., 

sources that are not subject to sourcespecific flared emissions reporting for 

your industry segment). 

(1) If you have a continuous flow 

measurement device on gas to the flare, 

you must use the measured flow 

volumes to calculate the flare gas 

emissions from miscellaneous flared 

sources. If all of the flare gas is not 

measured by the existing flow 

measurement device, then the flow not 

measured can be estimated using 

engineering calculations based on best 

available data. If you do not have a 

continuous flow measurement device on 

gas to the flare, or if a continuous flow 

measurement device measures a stream 

that combines flow from sources that are 

subject to source-specific flared 

emissions reporting as well as flow from 

miscellaneous flared sources, you can 

use engineering calculations based on 

process knowledge and best available 

data to estimate the flow from the 

miscellaneous flared sources. Best 

available data also includes the 

procedures specified in paragraphs 

(e)(5), (g)(4), (h)(2), (j)(5), (k)(5), (l)(6), 

and (m)(5) of this section. If a 

continuous flow measurement device is 

not installed on an AGR that is routed 

to a flare, the volumetric CO2 emissions 

calculated using AGR Calculation 

Method 3 or 4 and paragraph (d)(9) of 

this section must be incorporated into 

the parameter Vs in Equation W–20 to 

account for the AGR portion of the total 

flared CO2 emissions. 

(2) If you have a continuous gas 

composition analyzer on gas to the flare, 

you must use these compositions in 

calculating emissions from 

miscellaneous flared sources, except 

when the measured stream to the flare 

includes emissions from an AGR unit 

that are comingled with emissions from 

other sources. If you do not have a 

continuous gas composition analyzer on 

gas to the flare, or if the stream to the 

flare consists of AGR emissions that are 

comingled with emissions from other 

sources, you must use the appropriate 

gas compositions for each stream of 

hydrocarbons going to the flare from an 

emission source other than an AGR vent 

as specified in paragraphs (n)(2)(i) 

through (iii) of this section. For 

emissions from AGR vents that do not 

have a continuous gas composition 

analyzer, you may use either sitespecific engineering estimates based on 

best available data or a default CO2 mole 

fraction of 1. 

* * * * * 

(5) Calculate GHG volumetric 

emissions from flaring at standard 

conditions using Equations W–19 and 

W–20 of this section. Emissions may be 

calculated per stream routed to the flare 

and then summed over all streams per 

emissions source type. Alternatively, 

you may sum the total volume of all 

streams from a particular emission 

source type, determine the flowweighted average CO2 and hydrocarbon 

concentrations over all streams per 

source type, and then perform a single 

calculation using Equation W–19 and a 

single calculation using Equation W–20 

to calculate the total CH4 and CO2

emissions per source type. 


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Where: 

Es,CH4 = Annual CH4 emissions per emission 

source type from flare stack in cubic feet, 

at standard conditions. 

Es,CO2 = Annual CO2 emissions per emission 

source type from flare stack in cubic feet, 

at standard conditions. 

Vs = Volume of gas sent to flare per emission 

source type in standard cubic feet, 

during the year as determined in 

paragraph (e)(5)(i), (g)(4)(i), (h)(2)(i), 

(j)(5)(i), (l)(6)(i), (m)(5)(i), or (n)(1) of this 

section. 

h = Flare combustion efficiency, expressed as 

fraction of gas combusted by a burning 

flare (default is 0.98). 

XCH4 = Mole fraction of CH4 in the feed gas 

to the flare per emission source type as 

determined in paragraph (e)(5)(ii), 

(g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii), 

(m)(5)(ii), or (n)(2) of this section. Use a 

flow-weighted mole fraction if multiple 

streams from the same source type are 

combined for the emissions calculation. 

XCO2 = Mole fraction of CO2 in the feed gas 

to the flare per emission source type as 

determined in paragraph (e)(5)(ii), 

(g)(4)(ii), (h)(2)(ii), (j)(5)(ii), (l)(6)(ii), 

(m)(5)(ii), or (n)(2) of this section. Use a 

flow-weighted mole fraction if multiple 

streams from the same source type are 

combined for the emissions calculation. 

ZU = Fraction of the feed gas sent to an unlit flare per emission source type 

determined by engineering estimate and 

process knowledge based on best 

available data and operating records. 

ZL = Fraction of the feed gas sent to a burning 

flare per emission source type (equal to 

1 ¥ ZU). 

Yj = Mole fraction of hydrocarbon 

constituents j (such as methane, ethane, 

propane, butane, and pentanes-plus) in 

the feed gas to the flare per emissions 

source type as determined in paragraph 

(e)(5)(ii), (g)(4)(ii), (h)(2)(ii), (j)(5)(ii), 

(l)(6)(ii), (m)(5)(ii), or (n)(2) of this 

section. 

Rj = Number of carbon atoms in the 

hydrocarbon constituent j in the feed gas 

to the flare per emission source type: 1 

for methane, 2 for ethane, 3 for propane, 

4 for butane, and 5 for pentanes-plus). 

* * * * * 

(o) Centrifugal compressor venting. If 

you are required to report emissions 

from centrifugal compressor venting as 

specified in § 98.232(d)(2), (e)(2), (f)(2), 

(g)(2), and (h)(2), you must conduct 

volumetric emission measurements 

specified in paragraph (o)(1) of this 

section using methods specified in 

paragraphs (o)(2) through (5) of this 

section; perform calculations specified 

in paragraphs (o)(6) through (9) of this 

section; and calculate CH4 and CO2

mass emissions as specified in 

paragraph (o)(11) of this section. If you 

are required to report emissions from 

centrifugal compressor venting at an 

onshore petroleum and natural gas 

production facility as specified in 

§ 98.232(c)(19) or an onshore petroleum 

and natural gas gathering and boosting 

facility as specified in § 98.232(j)(8), you 

must calculate volumetric emissions as 

specified in paragraph (o)(10); and 

calculate CH4 and CO2 mass emissions 

as specified in paragraph (o)(11). If 

emissions from a compressor source are 

routed to a flare, paragraphs (o)(1) 

through (11) do not apply and instead 

you must calculate CH4, CO2, and N2O 

emissions as specified in paragraph 

(o)(12) of this section. If emissions from 

a compressor source are routed to 

combustion, paragraphs (o)(1) through 

(12) do not apply and instead you must 

calculate and report emissions as 

specified in subpart C of this part or 

paragraph (z) of this section, as 

applicable. If emissions from a 

compressor source are routed to vapor 

recovery, paragraphs (o)(1) through (12) 

do not apply. 

(1) * * * 

(i) Centrifugal compressor source as 

found measurements. Measure venting 

from each compressor according to 

either paragraph (o)(1)(i)(A), (B), or (C) 

of this section at least once annually, 

based on the compressor mode (as 

defined in § 98.238) in which the 

compressor was found at the time of 

measurement, except as specified in 

paragraph (o)(1)(i)(D) of this section. If 

additional measurements beyond the 

required annual testing are performed 

(including duplicate measurements or 

measurement of additional operating 

modes), then all measurements 

satisfying the applicable monitoring and 

QA/QC that is required by this 

paragraph (o) must be used in the 

calculations specified in this section. 

(A) For a compressor measured in 

operating-mode, you must measure 

volumetric emissions from blowdown 

valve leakage through the blowdown 

vent as specified in paragraph (o)(2)(i) of 

this section, measure volumetric 

emissions from wet seal oil degassing 

vents as specified in paragraph (o)(2)(ii) 

of this section if the compressor has wet 

seal oil degassing vents, and measure 

volumetric emissions from dry seal 

vents as specified in paragraph (o)(2)(iii) 

of this section if the compressor has dry 

seals. 

(B) For a compressor measured in notoperating-depressurized-mode, you 

must measure volumetric emissions 

from isolation valve leakage as specified 

in paragraph (o)(2)(i) of this section. If 

a compressor is not operated and has 

blind flanges in place throughout the 

reporting period, measurement is not 

required in this compressor mode. 

(C) For a compressor measured in 

standby-pressurized-mode, you must 

measure volumetric emissions from 

blowdown valve leakage through the 

blowdown vent as specified in 

paragraph (o)(2)(i) of this section, 

measure volumetric emissions from wet 

seal oil degassing vents as specified in 

paragraph (o)(2)(ii) of this section if the 

compressor has wet seal oil degassing 

vents, and measure volumetric 

emissions from dry seal vents as 

specified in paragraph (o)(2)(iii) of this 

section if the compressor has dry seals. 

* * * * * 

(2) Methods for performing as found 

measurements from individual 

centrifugal compressor sources. If 

conducting measurements for each 

compressor source, you must determine 

the volumetric emissions from 

blowdown valves and isolation valves 

as specified in paragraph (o)(2)(i) of this 

section, the volumetric emissions from 

wet seal oil degassing vents as specified 

in paragraph (o)(2)(ii) of this section, 

and the volumetric emissions from dry 

seal vents as specified in paragraph 

(o)(2)(iii) of this section. 

(i) For blowdown valves on 

compressors in operating-mode or in 

standby-pressurized-mode and for 

isolation valves on compressors in notoperating-depressurized-mode, 

determine the volumetric emissions 

using one of the methods specified in 

paragraphs (o)(2)(i)(A) through (D) of 

this section. 

* * * * * 

(ii) For wet seal oil degassing vents in 

operating-mode or in standbypressurized-mode, determine 

volumetric flow at standard conditions, 

using one of the methods specified in 

paragraphs (o)(2)(ii)(A) through (C) of 

this section. You must quantitatively 

measure the volumetric flow for wet 

seal oil degassing vent; you may not use 

screening methods set forth in 

§ 98.234(a) to screen for emissions for 

the wet seal oil degassing vent. 

(A) Use a temporary meter such as a 

vane anemometer or permanent flow 

meter according to methods set forth in 

§ 98.234(b). 

(B) Use calibrated bags according to 

methods set forth in § 98.234(c). 


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(C) Use a high volume sampler 

according to methods set forth in 

§ 98.234(d). 

(iii) For dry seal vents in operatingmode or in standby-pressurized-mode, 

determine volumetric flow at standard 

conditions from each dry seal vent using 

one of the methods specified in 

paragraphs (o)(2)(ii)(A) through (D) of 

this section. If a compressor has more 

than one dry seal vent, determine the 

aggregate dry seal vent volumetric flow 

for the compressor as the sum of the 

volumetric flows determined for each 

dry seal vent on the compressor. 

(A) Use a temporary meter such as a 

vane anemometer or permanent flow 

meter according to methods set forth in 

§ 98.234(b). 

(B) Use calibrated bags according to 

methods set forth in § 98.234(c). 

(C) Use a high volume sampler 

according to methods set forth in 

§ 98.234(d). 

(D) You may choose to use any of the 

methods set forth in § 98.234(a)(1) 

through (3) to screen for emissions. If 

emissions are detected using one of 

these specified methods, then you must 

use one of the methods specified in 

paragraph (o)(2)(iii)(A) through (C) of 

this section. If emissions are not 

detected using the methods in 

§ 98.234(a)(1) through (3), then you may 

assume that the volumetric emissions 

are zero. For the purposes of this 

paragraph, when using any of the 

methods in § 98.234(a), emissions are 

detected whenever a leak is detected 

according to the methods. Acoustic leak 

detection is only applicable for throughvalve leakage and is not applicable for 

screening dry seal vents. 

* * * * * 

(4) * * * 

(ii) * * * 

(E) You may choose to use any of the 

methods set forth in § 98.234(a)(1) 

through (3) to screen for emissions. If 

emissions are detected using one of 

these methods, then you must use one 

of the methods specified in paragraph 

(o)(4)(ii)(A) through (D) of this section. 

If emissions are not detected using the 

methods in § 98.234(a)(1) through (3), 

then you may assume that the 

volumetric emissions are zero. For the 

purposes of this paragraph, when using 

any of the methods in § 98.234(a), 

emissions are detected whenever a leak 

is detected according to the method. 

Acoustic leak detection is only 

applicable for through-valve leakage and 

is not applicable for screening a 

manifolded group of compressor 

sources. 

* * * * * 

(6) * * * 

(i) Using Equation W–21 of this 

section, calculate the annual volumetric 

GHG emissions for each centrifugal 

compressor mode-source combination 

specified in paragraphs (o)(1)(i)(A) 

through (C) of this section that was 

measured during the reporting year. 

* * * * * 

m = Compressor mode-source combination 

specified in paragraph (o)(1)(i)(A), (B), or 

(C) of this section that was measured for 

the reporting year. 

(ii) Using Equation W–22 of this 

section, calculate the annual volumetric 

GHG emissions from each centrifugal 

compressor mode-source combination 

specified in paragraphs (o)(1)(i)(A) 

through (C) of this section that was not 

measured during the reporting year. 

* * * * * 

m = Compressor mode-source combination 

specified in paragraph (o)(1)(i)(A), (B), or 

(C) of this section that was not measured 

in the reporting year. 

(iii) Using Equation W–23 of this 

section, develop an emission factor for 

each compressor mode-source 

combination specified in paragraphs 

(o)(1)(i)(A) through (C) of this section. 

These emission factors must be 

calculated annually and used in 

Equation W–22 of this section to 

determine volumetric emissions from a 

centrifugal compressor in the modesource combinations that were not 

measured in the reporting year. 

* * * * * 

m = Compressor mode-source combination 

specified in paragraph (o)(1)(i)(A), (B), or 

(C) of this section. 

* * * * * 

(8) * * * 

Tg = Total time the manifolded group of 

compressor sources g had potential for 

emissions in the reporting year, in hours. 

Include all time during which at least 

one compressor source in the manifolded 

group of compressor sources g was in a 

mode-source combination specified in 

either paragraph (o)(1)(i)(A), (o)(1)(i)(B), 

(o)(1)(i)(C), (p)(1)(i)(A), (p)(1)(i)(B), or 

(p)(1)(i)(C) of this section. Default of 

8760 hours may be used. 

* * * * * 

(10) Method for calculating 

volumetric GHG emissions from wet seal 

oil degassing vents at an onshore 

petroleum and natural gas production 

facility or an onshore petroleum and 

natural gas gathering and boosting 

facility. You must calculate emissions 

from atmospheric centrifugal 

compressor wet seal oil degassing vents 

at an onshore petroleum and natural gas 

production facility or an onshore 

petroleum and natural gas gathering and 

boosting facility using Equation W–25 of 

this section. Emissions from centrifugal 

compressor wet seal oil degassing vents 

that are routed to a flare, combustion, or 

vapor recovery are not required to be 

determined under this paragraph (o). 

* * * * * 

Count = Total number of centrifugal 

compressors that have wet seal oil 

degassing vents that are vented to the 

atmosphere. 

* * * * * 

(p) Reciprocating compressor venting. 

If you are required to report emissions 

from reciprocating compressor venting 

as specified in § 98.232(d)(1), (e)(1), 

(f)(1), (g)(1), and (h)(1), you must 

conduct volumetric emission 

measurements specified in paragraph 

(p)(1) of this section using methods 

specified in paragraphs (p)(2) through 

(5) of this section; perform calculations 

specified in paragraphs (p)(6) through 

(9) of this section; and calculate CH4 

and CO2 mass emissions as specified in 

paragraph (p)(11) of this section. If you 

are required to report emissions from 

reciprocating compressor venting at an 

onshore petroleum and natural gas 

production facility as specified in 

§ 98.232(c)(11) or an onshore petroleum 

and natural gas gathering and boosting 

facility as specified in § 98.232(j)(5), you 

must calculate volumetric emissions as 

specified in paragraph (p)(10); and 

calculate CH4 and CO2 mass emissions 

as specified in paragraph (p)(11). If 

emissions from a compressor source are 

routed to a flare, paragraphs (p)(1) 

through (11) do not apply and instead 

you must calculate CH4, CO2, and N2O 

emissions as specified in paragraph 

(p)(12) of this section. If emissions from 

a compressor source are routed to 

combustion, paragraphs (p)(1) through 

(12) do not apply and instead you must 

calculate and report emissions as 

specified in subpart C of this part or 

paragraph (z) of this section, as 

applicable. If emissions from a 

compressor source are routed to vapor 

recovery, paragraphs (p)(1) through (12) 

do not apply. 

(1) * * * 

(i) Reciprocating compressor source 

as found measurements. Measure 

venting from each compressor according 

to either paragraph (p)(1)(i)(A), (B), or 

(C) of this section at least once annually, 

based on the compressor mode (as 

defined in § 98.238) in which the 

compressor was found at the time of 

measurement, except as specified in 

paragraph (p)(1)(i)(D) of this section. If 

additional measurements beyond the 

required annual testing are performed 

(including duplicate measurements or 

measurement of additional operating 

modes), then all measurements 

satisfying the applicable monitoring and 

QA/QC that is required by this 


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paragraph (p) must be used in the 

calculations specified in this section. 

(A) For a compressor measured in 

operating-mode, you must measure 

volumetric emissions from blowdown 

valve leakage through the blowdown 

vent as specified in paragraph (p)(2)(i) 

of this section, and measure volumetric 

emissions from reciprocating rod 

packing as specified in paragraph 

(p)(2)(ii) or (iii) of this section, as 

applicable. 

(B) For a compressor measured in notoperating-depressurized-mode, you 

must measure volumetric emissions 

from isolation valve leakage as specified 

in paragraph (p)(2)(i) of this section. If 

a compressor is not operated and has 

blind flanges in place throughout the 

reporting period, measurement is not 

required in this compressor mode. 

(C) For a compressor measured in 

standby-pressurized-mode, you must 

measure volumetric emissions from 

blowdown valve leakage through the 

blowdown vent as specified in 

paragraph (p)(2)(i) of this section and 

measure volumetric emissions from 

reciprocating rod packing as specified in 

paragraph (p)(2)(ii) or (iii) of this 

section, as applicable. 

(D) An annual as found measurement 

is not required in the first year of 

operation for any new compressor that 

begins operation after as found 

measurements have been conducted for 

all existing compressors. For only the 

first year of operation of new 

compressors, calculate emissions 

according to paragraph (p)(6)(ii) of this 

section. 

* * * * * 

(2) Methods for performing as found 

measurements from individual 

reciprocating compressor sources. If 

conducting measurements for each 

compressor source, you must determine 

the volumetric emissions from 

blowdown valves and isolation valves 

as specified in paragraph (p)(2)(i) of this 

section. You must determine the 

volumetric emissions from reciprocating 

rod packing as specified in paragraph 

(p)(2)(ii) or (iii) of this section, as 

applicable. 

* * * * * 

(ii) For reciprocating rod packing 

equipped with an open-ended vent line 

on compressors in operating-mode or 

standby-pressurized-mode, determine 

the volumetric emissions using one of 

the methods specified in paragraphs 

(p)(2)(ii)(A) through (C) of this section. 

* * * * * 

(C) You may choose to use any of the 

methods set forth in § 98.234(a)(1) 

through (3) to screen for emissions. If 

emissions are detected using one of 

these specified methods, then you must 

use one of the methods specified in 

paragraph (p)(2)(ii)(A) and (B) of this 

section. If emissions are not detected 

using the methods in § 98.234(a)(1) 

through (3), then you may assume that 

the volumetric emissions are zero. For 

the purposes of this paragraph 

(p)(2)(ii)(C), when using any of the 

methods in § 98.234(a), emissions are 

detected whenever a leak is detected 

according to the method. Acoustic leak 

detection is only applicable for throughvalve leakage and is not applicable for 

screening or measuring rod packing 

emissions. 

(iii) * * * 

(A) You must use the methods 

described in § 98.234(a)(1) through (3) to 

conduct annual leak detection of 

equipment leaks from the packing case 

into an open distance piece, or for 

compressors with a closed distance 

piece, conduct annual detection of gas 

emissions from the rod packing vent, 

distance piece vent, compressor crank 

case breather cap, or other vent emitting 

gas from the rod packing. Acoustic leak 

detection is only applicable for throughvalve leakage and is not applicable for 

screening rod packing emissions. 

* * * * * 

(4) * * * 

(ii) * * * 

(C) A high volume sampler according 

to methods set forth in § 98.234(d). 

* * * * * 

(E) You may choose to use any of the 

methods set forth in § 98.234(a)(1) 

through (3) to screen for emissions. If 

emissions are detected using one of 

these specified methods, then you must 

use one of the methods specified in 

paragraph (p)(4)(ii)(A) through (D) of 

this section. If emissions are not 

detected using the methods in 

§ 98.234(a)(1) through (3), then you may 

assume that the volumetric emissions 

are zero. For the purposes of this 

paragraph, when using any of the 

methods in § 98.234(a), emissions are 

detected whenever a leak is detected 

according to the method. Acoustic leak 

detection is only applicable for throughvalve leakage and is not applicable for 

screening a manifolded group of 

compressor sources. 

* * * * * 

(6) * * * 

(ii) Using Equation W–27 of this 

section, calculate the annual volumetric 

GHG emissions from each reciprocating 

compressor mode-source combination 

specified in paragraphs (p)(1)(i)(A) 

through (C) of this section that was not 

measured during the reporting year. 

* * * * * 

(iii) Using Equation W–28 of this 

section, develop an emission factor for 

each compressor mode-source 

combination specified in paragraphs 

(p)(1)(i)(A) through (C) of this section. 

These emission factors must be 

calculated annually and used in 

Equation W–27 of this section to 

determine volumetric emissions from a 

reciprocating compressor in the modesource combinations that were not 

measured in the reporting year. 

* * * * * 

(10) Method for calculating 

volumetric GHG emissions from 

reciprocating compressor venting at an 

onshore petroleum and natural gas 

production facility or an onshore 

petroleum and natural gas gathering 

and boosting facility. You must 

calculate emissions from reciprocating 

compressor atmospheric venting of rod 

packing emissions at an onshore 

petroleum and natural gas production 

facility or an onshore petroleum and 

natural gas gathering and boosting 

facility using Equation W–29D of this 

section. Reciprocating compressor rod 

packing emissions that are routed to a 

flare, combustion, or vapor recovery are 

not required to be determined under 

this paragraph (p). 

* * * * * 

Count = Total number of reciprocating 

compressors with rod packing emissions 

vented to the atmosphere. 

* * * * * 

(q) Equipment leak surveys. For the 

components identified in paragraphs 

(q)(1)(i) through (iii) of this section, you 

must conduct equipment leak surveys 

using the leak detection methods 

specified in paragraphs (q)(1)(i) through 

(iii) and (v) of this section. For the 

components identified in paragraph 

(q)(1)(iv) of this section, you may elect 

to conduct equipment leak surveys, and 

if you elect to conduct surveys, you 

must use a leak detection method 

specified in paragraph (q)(1)(iv) of this 

section. This paragraph (q) applies to 

components in streams with gas content 

greater than 10 percent CH4 plus CO2 by 

weight. Components in streams with gas 

content less than or equal to 10 percent 

CH4 plus CO2 by weight are exempt 

from the requirements of this paragraph 

(q) and do not need to be reported. 

Tubing systems equal to or less than one 

half inch diameter are exempt from the 

requirements of this paragraph (q) and 

do not need to be reported. 

(1) Survey requirements. (i) For the 

components listed in § 98.232(e)(7), 

(f)(5), (g)(4), and (h)(5), that are not 

subject to the well site or compressor 

station fugitive emissions standards in 

§ 60.5397a of this chapter, the fugitive 


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emissions standards for well sites and 

compressor stations in part 60, subpart 

OOOOb of this chapter, or an applicable 

approved state plan or applicable 

Federal plan in part 62 of this chapter, 

you must conduct surveys using any of 

the leak detection methods listed in 

§ 98.234(a) and calculate equipment 

leak emissions using the procedures 

specified in either paragraph (q)(2) or (3) 

of this section. 

(ii) For the components listed in 

§ 98.232(i)(1), you must conduct surveys 

using any of the leak detection methods 

listed in § 98.234(a) except 

§ 98.234(a)(2)(ii) and calculate 

equipment leak emissions using the 

procedures specified in either paragraph 

(q)(2) or (3) of this section. 

(iii) For the components listed in 

§ 98.232(c)(21)(i), (e)(7) and (8), (f)(5) 

through (8), (g)(4), (g)(6) and (7), (h)(5), 

(h)(7) and (8), and (j)(10)(i) that are 

subject to the well site or compressor 

station fugitive emissions standards in 

§ 60.5397a of this chapter, the fugitive 

emissions standards for well sites and 

compressor stations in part 60, subpart 

OOOOb of this chapter, or an applicable 

approved state plan or applicable 

Federal plan in part 62 of this chapter, 

you must conduct surveys using any of 

the leak detection methods in 

§ 98.234(a)(1)(ii) or (iii) or (a)(2)(ii), as 

applicable, and calculate equipment 

leak emissions using the procedures 

specified in either paragraph (q)(2) or (3) 

of this section. 

(iv) For the components listed in 

§ 98.232(c)(21)(i), (e)(8), (f)(6) through 

(8), (g)(6) or (7), (h)(7) or (8), or (j)(10)(i), 

that are not subject to fugitive emissions 

standards in § 60.5397a of this chapter, 

the fugitive emissions standards for well 

sites and compressor stations in part 60, 

subpart OOOOb of this chapter, or an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter, you may elect to conduct 

surveys according to this paragraph (q), 

and, if you elect to do so, then you must 

use one of the leak detection methods in 

§ 98.234(a). 

(A) If you elect to use a leak detection 

method in § 98.234(a) for the surveyed 

component types in § 98.232(c)(21)(i), 

(f)(7), (g)(6), (h)(7), or (j)(10)(i) in lieu of 

the population count methodology 

specified in paragraph (r) of this section, 

then you must calculate emissions for 

the surveyed component types in 

§ 98.232(c)(21)(i), (f)(7), (g)(6), (h)(7), or 

(j)(10)(i) using the procedures in either 

paragraph (q)(2) or (3) of this section. 

(B) If you elect to use a leak detection 

method in § 98.234(a) for the surveyed 

component types in § 98.232(e)(8), (f)(6) 

and (8), (g)(7), and (h)(8), then you must 

use the procedures in either paragraph 

(q)(2) or (3) of this section to calculate 

those emissions. 

(C) If you elect to use a leak detection 

method in § 98.234(a)(1)(ii) or (iii), or 

(a)(2)(ii), as applicable, for any elective 

survey under this subparagraph 

(q)(1)(iv), then you must survey the 

component types in § 98.232(c)(21)(i), 

(e)(8), (f)(6) through (8), (g)(6) and (7), 

(h)(7) and (8), and (j)(10)(i) that are not 

subject to fugitive emissions standards 

in § 60.5397a of this chapter, the 

fugitive emissions standards for well 

sites and compressor stations in 40 CFR 

part 60, subpart OOOOb of this chapter, 

or an applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter, and you must calculate 

emissions from the surveyed component 

types in § 98.232(c)(21)(i), (e)(8), (f)(6) 

through (8), (g)(6) and (7), (h)(7) and (8), 

and (j)(10)(i) using the emission 

calculation requirements in either 

paragraph (q)(2) or (3) of this section. 

(v) For the components listed in 

§ 98.232(d)(7), you must conduct 

surveys as specified in paragraphs 

(q)(1)(v)(A) and (B) of this section and 

you must calculate equipment leak 

emissions using the procedures 

specified in either paragraph (q)(2) or (3) 

of this section. 

(A) For the components listed in 

§ 98.232(d)(7) that are not subject to the 

equipment leak standards in the 

equipment leak standards for processing 

plants in part 60, subpart OOOOb of this 

chapter, or an applicable approved state 

plan or applicable Federal plan in part 

62 of this chapter, you may use any of 

the leak detection methods listed in 

§ 98.234(a). 

(B) For the components listed in 

§ 98.232(d)(7) that are subject to the 

equipment leak standards in the 

equipment leak standards for processing 

plants in part 60, subpart OOOOb of this 

chapter, or an applicable approved state 

plan or applicable Federal plan in part 

62 of this chapter, you must use either 

of the leak detection methods in 

§ 98.234(a)(1)(iii) or (a)(2)(ii). 

(vi) Except as provided in paragraph 

(q)(1)(vii) of this section, you must 

conduct at least one complete leak 

detection survey in a calendar year. If 

you conduct multiple complete leak 

detection surveys in a calendar year, 

you must use the results from each 

complete leak detection survey when 

calculating emissions using the 

procedures specified in either paragraph 

(q)(2) or (3) of this section. Except as 

provided in paragraphs (q)(1)(v)(A) 

through (G) of this section, a complete 

leak detection survey is a survey in 

which all equipment components 

required to be surveyed as specified in 

paragraphs (q)(1)(i) through (v) of this 

section are surveyed. 

(A) For components subject to the 

well site and compressor station fugitive 

emissions standards in § 60.5397a of 

this chapter, each survey conducted in 

accordance with § 60.5397a of this 

chapter will be considered a complete 

leak detection survey for purposes of 

this section. 

(B) For components subject to the 

well site and compressor station fugitive 

emissions standards in the fugitive 

emissions standards for well sites and 

compressor stations in part 60, subpart 

OOOOb of this chapter, each survey 

conducted in accordance with the 

fugitive emissions standards for well 

sites and compressor stations in part 60, 

subpart OOOOb of this chapter will be 

considered a complete leak detection 

survey for purposes of this section. 

(C) For components subject to the 

well site and compressor station fugitive 

emissions standards in an applicable 

approved state plan or applicable 

Federal plan in part 62 of this chapter, 

each survey conducted in accordance 

with the applicable approved state plan 

or applicable Federal plan in part 62 of 

this chapter will be considered a 

complete leak detection survey for 

purposes of this section. 

(D) For an onshore petroleum and 

natural gas production facility electing 

to conduct leak detection surveys 

according to paragraph (q)(1)(iv) of this 

section, a survey of all required 

components at a single well-pad will be 

considered a complete leak detection 

survey for purposes of this section. 

(E) For an onshore petroleum and 

natural gas gathering and boosting 

facility electing to conduct leak 

detection surveys according to 

paragraph (q)(1)(iv) of this section, a 

survey of all required components at a 

gathering compressor station or 

centralized oil production site, as 

defined in § 98.238, will be considered 

a complete leak detection survey for 

purposes of this section. 

(F) For an onshore natural gas 

processing facility subject to the 

equipment leak standards for onshore 

natural gas processing plants in the 

equipment leak standards for onshore 

natural gas processing plants in part 60, 

subpart OOOOb of this chapter or an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter, each survey conducted in 

accordance with the equipment leak 

standards for onshore natural gas 

processing plants in part 60, subpart 

OOOOb of this chapter or an applicable 

approved state plan or applicable 

Federal plan in part 62 of this chapter 

will be considered a complete leak 


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detection survey for the purposes of 

calculating emissions using the 

procedures specified in either paragraph 

(q)(2) or (3) of this section. However, 

this provision does not absolve you of 

the responsibility to conduct a complete 

leak detection survey of all components 

listed in § 98.232(d)(7) and subject to 

this paragraph (q) at least once during 

the calendar year. 

(G) For natural gas distribution 

facilities that choose to conduct 

equipment leak surveys at all above 

grade transmission-distribution transfer 

stations over multiple years as provided 

in paragraph (q)(1)(vii) of this section, a 

survey of all required components at the 

above grade transmission-distribution 

transfer stations monitored during the 

calendar year will be considered a 

complete leak detection survey for 

purposes of this section. 

(vii) Natural gas distribution facilities 

are required to perform equipment leak 

surveys only at above grade stations that 

qualify as transmission-distribution 

transfer stations. Below grade 

transmission-distribution transfer 

stations and all metering-regulating 

stations that do not meet the definition 

of transmission-distribution transfer 

stations are not required to perform 

equipment leak surveys under this 

section. Natural gas distribution 

facilities may choose to conduct 

equipment leak surveys at all above 

grade transmission-distribution transfer 

stations over multiple years ‘‘n,’’ not 

exceeding a five-year period to cover all 

above grade transmission-distribution 

transfer stations. If the facility chooses 

to use the multiple year option, then the 

number of transmission-distribution 

transfer stations that are monitored in 

each year should be approximately 

equal across all years in the cycle. 

(2) Calculation Method 1: Leaker 

emission factor calculation 

methodology. If you elect to use this 

method, you must use this method for 

all components included in a complete 

leak survey. For industry segments 

listed in § 98.230(a)(2) through (9), if 

equipment leaks are detected during 

surveys required or elected for 

components listed in paragraphs 

(q)(1)(i) through (iv) of this section, then 

you must calculate equipment leak 

emissions per component type per 

reporting facility using Equation W–30 

of this section and the requirements 

specified in paragraphs (q)(2)(i) through 

(ix) of this section. For the industry 

segment listed in § 98.230(a)(8), the 

results from Equation W–30 are used to 

calculate population emission factors on 

a meter/regulator run basis using 

Equation W–31 of this section. If you 

chose to conduct equipment leak 

surveys at all above grade transmissiondistribution transfer stations over 

multiple years, ‘‘n,’’ according to 

paragraph (q)(1)(vii) of this section, then 

you must calculate the emissions from 

all above grade transmissiondistribution transfer stations as 

specified in paragraph (q)(2)(xi) of this 

section. 

* * * * * 

EFs,p = Leaker emission factor for specific 

component types by leak detection 

method listed in Tables W–1E, W–2A, 

W–3A, W–4A, W–5A, W–6A, and W–7A 

to this subpart. 

* * * * * 

(i) The leak detection surveys selected 

for use in Equation W–30 must be 

conducted during the calendar year as 

indicated in paragraph (q)(1)(vi) and 

(vii) of this section, as applicable. 

* * * * * 

(iii) Onshore petroleum and natural 

gas production facilities must use the 

appropriate default whole gas leaker 

emission factors consistent with the 

well type, where components associated 

with gas wells are considered to be in 

gas service and components associated 

with oil wells are considered to be in oil 

service as listed in Table W–1E to this 

subpart. 

* * * * * 

(v) Onshore natural gas processing 

facilities must use the appropriate 

default total hydrocarbon leaker 

emission factors for compressor 

components in gas service and noncompressor components in gas service 

listed in Table W–2A to this subpart. 

* * * * * 

(x) Natural gas distribution facilities 

must use Equation W–30 of this section 

and the default methane leaker emission 

factors for transmission-distribution 

transfer station components in gas 

service listed in Table W–7 to this 

subpart to calculate component 

emissions from annual equipment leak 

surveys conducted at above grade 

transmission-distribution transfer 

stations. 

(A) Use Equation W–31 of this section 

to determine the meter/regulator run 

population emission factors for each 

GHGi. As additional survey data become 

available, you must recalculate the 

meter/regulator run population 

emission factors for each GHGi annually 

according to paragraph (q)(2)(x)(B) of 

this section. 

Where: 

EFs,MR,i = Meter/regulator run population 

emission factor for GHGi based on all 

surveyed above grade transmissiondistribution transfer stations over ‘‘n’’ 

years, in standard cubic feet of GHGi per 

operational hour of all meter/regulator 

runs. 

Es,p,i,y = Annual total volumetric emissions at 

standard conditions of GHGi from 

component type ‘‘p’’ during year ‘‘y’’ in 

standard (‘‘s’’) cubic feet, as calculated 

using Equation W–30 of this section. 

p = Seven component types listed in Table 

W–7 to this subpart for transmissiondistribution transfer stations. 

Tw,y = The total time the surveyed meter/ 

regulator run ‘‘w’’ was operational, in 

hours during survey year ‘‘y’’ using an 

engineering estimate based on best 

available data. 

CountMR,y = Count of meter/regulator runs 

surveyed at above grade transmissiondistribution transfer stations in year ‘‘y’’. 

y = Year of data included in emission factor 

‘‘EFs,MR,i’’ according to paragraph 

(q)(2)(x)(B) of this section. 

n = Number of years of data, according to 

paragraph (q)(1)(vii) of this section, 

whose results are used to calculate 

emission factor ‘‘EFs,MR,i’’ according to 

paragraph (q)(2)(x)(B) of this section. 

(B) The emission factor ‘‘EFs,MR,i’’ 

based on annual equipment leak surveys 

at above grade transmission-distribution 

transfer stations, must be calculated 

annually. If you chose to conduct 

equipment leak surveys at all above 

grade transmission-distribution transfer 

stations over multiple years, ‘‘n,’’ 

according to paragraph (q)(1)(vii) of this 

section and you have submitted a 

smaller number of annual reports than 

the duration of the selected cycle period 

of 5 years or less, then all available data 

from the current year and previous years 


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must be used in the calculation of the 

emission factor ‘‘EFs,MR,i’’ from Equation 

W–31 of this section. After the first 

survey cycle of ‘‘n’’ years is completed 

and beginning in calendar year (n+1), 

the survey will continue on a rolling 

basis by including the survey results 

from the current calendar year ‘‘y’’ and 

survey results from all previous (n¥1) 

calendar years, such that each annual 

calculation of the emission factor 

‘‘EFs,MR,i’’ from Equation W–31 is based 

on survey results from ‘‘n’’ years. Upon 

completion of a cycle, you may elect to 

change the number of years in the next 

cycle period (to be 5 years or less). If the 

number of years in the new cycle is 

greater than the number of years in the 

previous cycle, calculate ‘‘EFs,MR,i’’ from 

Equation W–31 in each year of the new 

cycle using the survey results from the 

current calendar year and the survey 

results from the preceding number years 

that is equal to the number of years in 

the previous cycle period. If the number 

of years, ‘‘nnew,’’ in the new cycle is 

smaller than the number of years in the 

previous cycle, ‘‘n,’’ calculate ‘‘EFs,MR,i’’ 

from Equation W–31 in each year of the 

new cycle using the survey results from 

the current calendar year and survey 

results from all previous (nnew¥1) 

calendar years. 

(xi) If you chose to conduct 

equipment leak surveys at all above 

grade transmission-distribution transfer 

stations over multiple years, ‘‘n,’’ 

according to paragraph (q)(1)(vii) of this 

section, you must use the meter/ 

regulator run population emission 

factors calculated using Equation W–31 

of this section and the total count of all 

meter/regulator runs at above grade 

transmission-distribution transfer 

stations to calculate emissions from all 

above grade transmission-distribution 

transfer stations using Equation W–32B 

in paragraph (r) of this section. 

(3) Calculation Method 2: Leaker 

measurement methodology. If you elect 

to use this method, you must use this 

method for all components included in 

a complete leak survey. For industry 

segments listed in § 98.230(a)(2) through 

(9), if equipment leaks are detected 

during surveys required or elected for 

components listed in paragraphs 

(q)(1)(i) through (v) of this section, you 

must determine the volumetric flow rate 

of each natural gas leak identified 

during the leak survey and aggregate the 

emissions by component type as 

specified in paragraphs (q)(3)(i) through 

(vii) of this section. 

(i) Determine the volumetric flow rate 

of each natural gas leak identified 

during the leak survey following the 

methods § 98.234(b) through (d), as 

appropriate for each leak identified. You 

do not need to use the same 

measurement method for each leak 

measured. 

(ii) For each leak, calculate the 

volume of natural gas emitted as the 

product of the natural gas flow rate 

measured in paragraph (q)(3)(i) of this 

section and the duration of the leak. If 

one leak detection survey is conducted 

in the calendar year, assume the 

component was leaking for the entire 

calendar year. If multiple leak detection 

surveys are conducted in the calendar 

year, assume a component found 

leaking in the first survey was leaking 

since the beginning of the year until the 

date of the survey; assume a component 

found leaking in the last survey of the 

year was leaking from the preceding 

survey through the end of the year; 

assume a component found leaking in a 

survey between the first and last surveys 

of the year was leaking since the 

preceding survey until the date of the 

survey. For each leaking component, 

account for time the component was not 

operational (i.e., not operating under 

pressure) using an engineering estimate 

based on best available data. 

(iii) For each leak, convert the 

volumetric emissions of natural gas 

determined in paragraph (q)(3)(ii) of this 

section to standard conditions using the 

method specified in paragraph (t)(1) of 

this section. 

(iv) For each leak, convert the 

volumetric emissions of natural gas at 

standard conditions determined in 

paragraph (q)(3)(iii) of this section to 

CO2 and CH4 volumetric emissions at 

standard conditions using the methods 

specified in paragraph (u) of this 

section. 

(v) For each leak, convert the GHG 

volumetric emissions at standard 

conditions determined in paragraph 

(q)(3)(iv) of this section to GHG mass 

emissions using the methods specified 

in paragraph (v) of this section. 

(vi) Sum the CO2 and CH4 mass 

emissions determined in paragraph 

(q)(3)(v) of this section separately for 

each type of component required to be 

surveyed for which a leak was detected. 

(vii) For natural gas distribution 

facilities: 

(A) Use Equation W–31 of this section 

to determine the meter/regulator run 

population emission factors for each 

GHGi using the methods as specified in 

paragraphs (q)(2)(x)(A) and (B) of this 

section, except use the GHG mass 

emissions calculated in paragraph 

(q)(3)(vi) rather than the emissions 

calculated using Equation W–30. 

(B) If you chose to conduct equipment 

leak surveys at all above grade 

transmission-distribution transfer 

stations over multiple years, ‘‘n,’’ 

according to paragraph (q)(1)(vii) of this 

section, you must use the meter/ 

regulator run population emission 

factors calculated according to 

paragraph (q)(3)(vii)(A) of this section 

and the total count of all meter/regulator 

runs at above grade transmissiondistribution transfer stations to calculate 

emissions from all above grade 

transmission-distribution transfer 

stations using Equation W–32B in 

paragraph (r) of this section. 

(r) Equipment leaks by population 

count. This paragraph (r) applies to 

emissions sources listed in 

§ 98.232(c)(21)(ii), (f)(7), (g)(5), (h)(6), 

and (j)(10)(ii) if you are not required to 

comply with paragraph (q) of this 

section and if you do not elect to 

comply with paragraph (q) of this 

section for these components in lieu of 

this paragraph (r). This paragraph (r) 

also applies to emission sources listed 

in § 98.232(i)(2) through (6) and (j)(11). 

To be subject to the requirements of this 

paragraph (r), the listed emissions 

sources also must contact streams with 

gas content greater than 10 percent CH4

plus CO2 by weight. Emissions sources 

that contact streams with gas content 

less than or equal to 10 percent CH4

plus CO2 by weight are exempt from the 

requirements of this paragraph (r) and 

do not need to be reported. Tubing 

systems equal to or less than one half 

inch diameter are exempt from the 

requirements of paragraph (r) of this 

section and do not need to be reported. 

You must calculate emissions from all 

emission sources listed in this 

paragraph (r) using Equation W–32A of 

this section, except for natural gas 

distribution facility emission sources 

listed in § 98.232(i)(3). Natural gas 

distribution facility emission sources 

listed in § 98.232(i)(3) must calculate 

emissions using Equation W–32B of this 

section and according to paragraph 

(r)(6)(ii) of this section. 

* * * * * 

Es,e,i = Annual volumetric emissions of GHGi

from the emission source type in 

standard cubic feet. The emission source 

type may be a major equipment (e.g., 

wellhead, separator), component (e.g., 

connector, open-ended line), below 

grade metering-regulating station, below 

grade transmission-distribution transfer 

station, distribution main, distribution 

service, or gathering pipeline. 

Es,MR,i = Annual volumetric emissions of 

GHGi from all meter/regulator runs at 

above grade metering regulating stations 

that are not above grade transmissiondistribution transfer stations or, when 

used to calculate emissions according to 

paragraph (q)(2)(xi) or (q)(3)(vii)(B) of 

this section, the annual volumetric 

emissions of GHGi from all meter/ 

regulator runs at above grade 


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transmission-distribution transfer 

stations. 

Counte = Total number of the emission 

source type at the facility. Onshore 

petroleum and natural gas production 

facilities and onshore petroleum and 

natural gas gathering and boosting 

facilities must count each major 

equipment piece listed in Table W–1A to 

this subpart. Onshore petroleum and 

natural gas gathering and boosting 

facilities must also count the miles of 

gathering pipelines by material type 

(protected steel, unprotected steel, 

plastic, or cast iron). Underground 

natural gas storage facilities must count 

each component listed in Table W–4B to 

this subpart. LNG storage facilities must 

count the number of vapor recovery 

compressors. LNG import and export 

facilities must count the number of vapor 

recovery compressors. Natural gas 

distribution facilities must count the: (1) 

Number of distribution services by 

material type; (2) miles of distribution 

mains by material type; (3) number of 

below grade transmission-distribution 

transfer stations; and (4) number of 

below grade metering-regulating stations; 

as listed in Table W–8 to this subpart. 

CountMR = Total number of meter/regulator 

runs at above grade metering-regulating 

stations that are not above grade 

transmission-distribution transfer 

stations or, when used to calculate 

emissions according to paragraph 

(q)(2)(xi) or (q)(3)(vii)(B) of this section, 

the total number of meter/regulator runs 

at above grade transmission-distribution 

transfer stations. 

EFs,e = Population emission factor for the 

specific emission source type, as listed 

in Tables W–1A, W–4B, W–5B, W–6B, 

and W–8 to this subpart. 

* * * * * 

(2) Onshore petroleum and natural gas 

production facilities and onshore 

petroleum and natural gas gathering and 

boosting facilities must use the 

appropriate default whole gas 

population emission factors listed in 

Table W–1A of this subpart. Major 

equipment associated with gas wells are 

considered gas service equipment in 

Table W–1A of this subpart. Onshore 

petroleum and natural gas gathering and 

boosting facilities shall use the gas 

service equipment emission factors in 

Table W–1A of this subpart. Major 

equipment associated with crude oil 

wells are considered crude service 

equipment in Table W–1A of this 

subpart. Where facilities conduct EOR 

operations the emission factor listed in 

Table W–1A of this subpart shall be 

used to estimate all streams of gases, 

including recycle CO2 stream. For 

meters/piping, use one meters/piping 

per well-pad for onshore petroleum and 

natural gas production operations and 

the number of meters in the facility for 

onshore petroleum and natural gas 

gathering and boosting operations. 

* * * * * 

(6) * * * 

(i) Below grade transmissiondistribution transfer stations, below 

grade metering-regulating stations, 

distribution mains, and distribution 

services must use the appropriate 

default methane population emission 

factors listed in Table W–8 of this 

subpart to estimate emissions from 

components listed in § 98.232(i)(2), (4), 

(5), and (6), respectively. 

(ii) Above grade metering-regulating 

stations that are not above grade 

transmission-distribution transfer 

stations must use the meter/regulator 

run population emission factor 

calculated in Equation W–31 for the 

components listed in § 98.232(i)(3). 

Natural gas distribution facilities that do 

not have above grade transmissiondistribution transfer stations are not 

required to calculate emissions for 

above grade metering-regulating stations 

and are not required to report GHG 

emissions in § 98.236(r)(2)(v). 

(s) Offshore petroleum and natural 

gas production facilities. Report CO2, 

CH4, and N2O emissions for offshore 

petroleum and natural gas production 

from all equipment leaks, vented 

emission, and flare emission source 

types as identified in the data collection 

and emissions estimation study 

conducted by BOEM in compliance 

with 30 CFR 550.302 through 304. 

(1) Offshore production facilities 

under BOEM jurisdiction shall report 

the same annual emissions as calculated 

and reported by BOEM in data 

collection and emissions estimation 

study published by BOEM referenced in 

30 CFR 550.302 through 304. 

(i) For any calendar year that does not 

overlap with the most recent BOEM 

emissions study publication year, report 

the most recent BOEM reported 

emissions data published by BOEM 

referenced in 30 CFR 550.302 through 

304. Adjust emissions based on the 

operating time for the facility relative to 

the operating time in the most recent 

BOEM published study. 

(ii) [Reserved] 

(2) Offshore production facilities that 

are not under BOEM jurisdiction must 

use the most recent monitoring methods 

and calculation methods published by 

BOEM referenced in 30 CFR 550.302 

through 304 to calculate and report 

annual emissions. 

(i) For any calendar year that does not 

overlap with the most recent BOEM 

emissions study publication, you may 

report the most recently reported 

emissions data submitted to 

demonstrate compliance with this 

subpart of part 98, with emissions 

adjusted based on the operating time for 

the facility relative to operating time in 

the previous reporting period. 

(ii) [Reserved] 

(3) If BOEM discontinues or delays 

their data collection effort by more than 

4 years, then offshore reporters shall 

once in every 4 years use the most 

recent BOEM data collection and 

emissions estimation methods to 

estimate emissions. These emission 

estimates would be used to report 

emissions from the facility sources as 

required in paragraph (s)(1)(i) of this 

section. 

(4) For either first or subsequent year 

reporting, offshore facilities either 

within or outside of BOEM jurisdiction 

that were not covered in the previous 

BOEM data collection cycle must use 

the most recent BOEM data collection 

and emissions estimation methods 

published by BOEM referenced in 30 

CFR 550.302 through 304 to calculate 

and report emissions. 

(t) * * * 

(2) * * * 

* * * * * 

Za = Compressibility factor at actual 

conditions for GHGi. You may use either 

a default compressibility factor of 1, or 

a site-specific compressibility factor 

based on actual temperature and 

pressure conditions. 

* * * * * 

(u) * * * 

(2) * * * 

(ii) GHG mole fraction in feed natural 

gas for all emissions sources upstream 

of the de-methanizer or dew point 

control and GHG mole fraction in 

facility specific residue gas to 

transmission pipeline systems for all 

emissions sources downstream of the 

de-methanizer overhead or dew point 

control for onshore natural gas 

processing facilities. For onshore natural 

gas processing plants that solely 

fractionate a liquid stream, use the GHG 

mole percent in feed natural gas liquid 

for all streams. If you have a continuous 

gas composition analyzer on feed 

natural gas, you must use these values 

for determining the mole fraction. If you 

do not have a continuous gas 

composition analyzer, then annual 

samples must be taken according to 

methods set forth in § 98.234(b). 

* * * * * 

(y) Other large release events. 

Calculate CO2 and CH4 emissions from 

other release events for each release that 

emits GHG in excess of 250 metric tons 

of CO2e as specified in paragraphs (y)(1) 

through (4) of this section. 

(1) Estimate the total volume of gas 

released during the event in standard 


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cubic feet using any combination of 

measurement data, engineering 

estimates, and best available data. 

Typically, total volume of gas released 

would be estimated as the product of 

the estimated flow or release rate and 

the estimated event duration. 

(2) Determine the composition of the 

gas released to the atmosphere using 

measurement data, if available, or 

process knowledge, engineering 

estimates and best available data. In the 

event of an explosion or fire, where a 

portion of the natural gas may be 

combusted, estimate the composition of 

the gas released to the atmosphere 

considering the fraction of natural gas 

that was converted to CO2 during the 

release event. 

(3) Calculate the GHG volumetric 

emissions using Equation W–35 in 

paragraph (u)(1) of this section. 

(4) Calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculations in paragraph (v) of 

this section. 

(z) Onshore petroleum and natural 

gas production, onshore petroleum and 

natural gas gathering and boosting, and 

natural gas distribution combustion 

emissions. Except as specified in 

paragraphs (z)(5) and (6) of this section, 

calculate CO2, CH4, and N2O 

combustion-related emissions from 

stationary or portable equipment using 

the applicable method in paragraphs 

(z)(1) through (3) of this section 

according to the fuel combusted as 

specified in those paragraphs: 

(1) If a fuel combusted in the 

stationary or portable equipment meets 

the specifications of paragraph (z)(1)(i) 

of this section, then calculate emissions 

according to paragraph (z)(1)(ii) of this 

section. 

(i) The fuel combusted in the 

stationary or portable equipment is 

listed in Table C–1 of subpart C of this 

part or is a blend in which all fuels are 

listed in Table C–1. If the fuel is natural 

gas or the blend contains natural gas, 

the natural gas must also meet the 

criteria of paragraphs (z)(1)(i)(A) and (B) 

of this section. 

(A) The natural gas must be of 

pipeline quality specification. 

(B) The natural gas must have a 

minimum higher heating value of 950 

Btu per standard cubic foot. 

(ii) For fuels listed in paragraph 

(z)(1)(i) of this section, calculate CO2, 

CH4, and N2O emissions according to 

any Tier listed in subpart C of this part, 

except that natural gas-fired 

compressor-drivers must use the 

appropriate emission factor in Table W– 

9 for quantifying CH4 emissions instead 

of the CH4 emission factor in Table C– 

2 of subpart C of this part. You must 

follow all applicable calculation 

requirements for that tier listed in 

§ 98.33, any monitoring or QA/QC 

requirements listed for that tier in 

§ 98.34, any missing data procedures 

specified in § 98.35, and any 

recordkeeping requirements specified in 

§ 98.37. You must report emissions 

according to paragraph (z)(4) of this 

section. 

(2) If a fuel combusted in the 

stationary or portable equipment meets 

the specifications of paragraph (z)(2)(i) 

of this section, then calculate emissions 

according to paragraph (z)(2)(ii) of this 

section. 

(i) The fuel combusted in the 

stationary or portable equipment is 

natural gas that is not pipeline quality 

or it is a blend containing natural gas 

that is not pipeline quality and other 

gaseous fuels listed in Table C–1. The 

natural gas also must meet the criteria 

of paragraphs (z)(2)(i)(A) through (C) of 

this section. 

(A) The natural gas must have a 

minimum higher heating value of 950 

Btu per standard cubic foot. 

(B) The natural gas must have a 

maximum CO2 content of 1 percent by 

volume. 

(C) The natural gas must have a 

minimum CH4 content of 85 percent by 

volume. 

(ii) For fuels listed in paragraph 

(z)(2)(i) of this section, calculate CO2, 

CH4, and N2O emissions according to 

Tier 2, Tier 3, or Tier 4 listed in subpart 

C of this part, except that natural gasfired compressor-drivers must use the 

appropriate emissions factor in Table 

W–9 for quantifying CH4 emissions 

instead of the CH4 emission factor in 

Table C–2 of subpart C of this part. You 

must follow all applicable calculation 

requirements for that tier listed in 

§ 98.33, any monitoring or QA/QC 

requirements listed for that tier in 

§ 98.34, any missing data procedures 

specified in § 98.35, and any 

recordkeeping requirements specified in 

§ 98.37. You must report emissions 

according to paragraph (z)(4) of this 

section. 

(3) If a fuel combusted in the 

stationary or portable equipment meets 

the specifications of paragraph (z)(3)(i) 

of this section, then calculate emissions 

according to paragraph (z)(3)(ii) of this 

section. 

(i) The fuel is not listed in Table C– 

1 of subpart C of this part, the fuel is 

a blend containing one or more fuels not 

listed in Table C–1, or the fuel is natural 

gas or contains natural gas that does not 

meet the criteria of either paragraph 

(z)(1)(i) or (z)(2)(i) of this section. This 

includes natural gas that has a higher 

heating value of less than 950 Btu per 

standard cubic feet and natural gas that 

is not pipeline quality and does not 

meet the composition criteria of either 

paragraph (z)(2)(i)(B) or (C) of this 

section. This also includes field gas that 

does not meet the definition of natural 

gas in § 98.238, and blends containing 

field gas that does not meet the 

definition of natural gas in § 98.238. 

(ii) For fuels listed in paragraph 

(z)(3)(i) of this section, calculate 

combustion emissions for each unit or 

group of units combusting the same fuel 

as follows: 

(A) You may use company records to 

determine the volume of fuel combusted 

in the unit or group of units during the 

reporting year. 

(B) If you have a continuous gas 

composition analyzer on fuel to the 

combustion unit(s), you must use these 

compositions for determining the 

concentration of each hydrocarbon 

constituent in the flow of gas to the unit 

or group of units. If you do not have a 

continuous gas composition analyzer on 

gas to the combustion unit(s), you may 

use engineering estimates based on best 

available data to determine the 

concentration of each hydrocarbon 

constituent in the flow of gas to the unit 

or group of units. Otherwise, you must 

use the appropriate gas compositions for 

each stream of hydrocarbons going to 

the combustion unit(s) as specified in 

the applicable paragraph in (u)(2) of this 

section. 

(C) Calculate GHG volumetric 

emissions at actual conditions using 

Equations W–39A and W–39B of this 

section: 


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Where: 

Ea,CO2 = Contribution of annual CO2

emissions from portable or stationary 

fuel combustion sources in cubic feet, 

under actual conditions. 

Va = Volume of gas sent to the combustion 

unit or group of units in actual cubic 

feet, during the year. 

YCO2 = Mole fraction of CO2 in gas sent to 

the combustion unit or group of units. 

Ea,CH4 = Contribution of annual CH4

emissions from portable or stationary 

fuel combustion sources in cubic feet, 

under actual conditions. 

h = Fraction of gas combusted for portable 

and stationary equipment determined 

using engineering estimation. For 

internal combustion devices that are not 

compressor-drivers, a default of 0.995 

can be used. For two-stroke lean-burn 

compressor-drivers, a default of 0.953 

must be used; for four- stroke lean-burn 

compressor-drivers, a default of 0.962 

must be used; and for four-stroke richburn compressor-drivers, a default of 

0.997 must be used. 

Yj = Mole fraction of hydrocarbon constituent 

j (such as methane, ethane, propane, 

butane, and pentanes plus) in gas sent to 

the combustion unit or group of units. 

Rj = Number of carbon atoms in the 

hydrocarbon constituent j in gas sent to 

the combustion unit or group of units; 1 

for methane, 2 for ethane, 3 for propane, 

4 for butane, and 5 for pentanes plus. 

YCH4 = Mole fraction of methane in gas sent 

to the combustion unit or group of units. 

(D) Calculate GHG volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(E) Calculate both combustion-related 

CH4 and CO2 mass emissions from 

volumetric CH4 and CO2 emissions 

using calculation in paragraph (v) of this 

section. 

(F) Calculate N2O mass emissions 

using Equation W–40 of this section. 

Where: 

MassN2O = Annual N2O emissions from the 

combustion of a particular type of fuel 

(metric tons). 

Fuel = Annual mass or volume of the fuel 

combusted (mass or volume per year, 

choose appropriately to be consistent 

with the units of HHV). 

HHV = Higher heating value of fuel, mmBtu/ 

unit of fuel (in units consistent with the 

fuel quantity combusted). For field gas or 

process vent gas, you may use either a 

default higher heating value of 1.235 × 

10¥3 mmBtu/scf or a site-specific higher 

heating value. For natural gas that is not 

of pipeline quality or that has a higher 

heating value less than 950 Btu per 

standard cubic foot, use a site-specific 

higher heating value. 

EF = Use 1.0 × 10¥4 kg N2O/mmBtu. 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(4) Emissions from fuel combusted in 

stationary or portable equipment at 

onshore petroleum and natural gas 

production facilities, at onshore 

petroleum and natural gas gathering and 

boosting facilities, and at natural gas 

distribution facilities that are calculated 

according to the procedures in either 

paragraph (z)(1)(ii) or (z)(2)(ii) of this 

section must be reported according to 

the requirements specified in § 98.236(z) 

rather than the reporting requirements 

specified in subpart C of this part. 

(5) External fuel combustion sources 

with a rated heat capacity equal to or 

less than 5 mmBtu/hr do not need to 

report combustion emissions or include 

these emissions for threshold 

determination in § 98.231(a). You must 

report the type and number of each 

external fuel combustion unit. 

(6) Internal fuel combustion sources, 

not compressor-drivers, with a rated 

heat capacity equal to or less than 1 

mmBtu/hr (or the equivalent of 130 

horsepower), do not need to report 

combustion emissions or include these 

emissions for threshold determination 

in § 98.231(a). You must report the type 

and number of each internal fuel 

combustion unit. 

■ 58. Amend § 98.234 by revising the 

introductory text, paragraph (a), and 

paragraph (d)(3) and adding paragraphs 

(d)(5) and (i) to read as follows: 

§ 98.234 Monitoring and QA/QC 

requirements. 

The GHG emissions data for 

petroleum and natural gas emissions 

sources must be quality assured as 

applicable as specified in this section. 

Offshore petroleum and natural gas 

production facilities shall adhere to the 

monitoring and QA/QC requirements as 

set forth in 30 CFR 550. 

(a) You must use any of the applicable 

methods described in paragraphs (a)(1) 

through (5) of this section to conduct 

leak detection(s) or screening survey(s) 

as specified in § 98.233(k), (o), and (p) 

that occur during a calendar year. You 

must use any of the methods described 

in paragraphs (a)(1) through (5) of this 

section to conduct leak detection(s) of 

equipment leaks from components as 

specified in § 98.233(q)(1)(i) or (ii) or 

(q)(1)(v)(A) that occur during a calendar 

year. You must use one of the methods 

described in paragraph (a)(1)(ii) or (iii) 

or (a)(2)(ii) of this section, as applicable, 

to conduct leak detection(s) of 

equipment leaks from components as 

specified in § 98.233(q)(1)(iii) or 

(q)(1)(v)(B). If electing to comply with 

§ 98.233(q) as specified in 

§ 98.233(q)(1)(iv), you must use any of 

the methods described in paragraphs 

(a)(1) through (5) of this section to 

conduct leak detection(s) of equipment 

leaks from component types as specified 

in § 98.233(q)(1)(iv) that occur during a 

calendar year. Inaccessible emissions 

sources, as defined in 40 CFR part 60, 

are not exempt from this subpart. If the 

primary leak detection method 

employed cannot be used to monitor 

inaccessible components without 

elevating the monitoring personnel 

more than 2 meters above a support 

surface, you must use alternative leak 

detection devices as described in 

paragraph (a)(1) or (3) of this section to 

monitor inaccessible equipment leaks or 

vented emissions at least once per 

calendar year. 

(1) Optical gas imaging instrument. 

Use an optical gas imaging instrument 

for equipment leak detection as 

specified in either paragraph (a)(1)(i), 

(ii), or (iii) of this section. You may use 

any of the methods as specified in 

paragraphs (a)(1)(i) through (iii) of this 

section unless you are required to use a 

specific method to comply with the 

fugitive emission component 

requirements in part 60, subpart OOOOa 

of this chapter or with the fugitive 

emission component or equipment leak 

requirements in part 60, OOOOb of this 

chapter or with the fugitive emission 

component or equipment leak 

requirements in an applicable approved 

state plan or applicable Federal plan in 

part 62 of this chapter. 

(i) Optical gas imaging instrument as 

specified in § 60.18 of this chapter. Use 

an optical gas imaging instrument for 

equipment leak detection in accordance 

with 40 CFR part 60, subpart A, § 60.18 

of the Alternative work practice for 

monitoring equipment leaks, 

§ 60.18(i)(1)(i); § 60.18(i)(2)(i) except 


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that the minimum monitoring frequency 

shall be annual using the detection 

sensitivity level of 60 grams per hour as 

stated in 40 CFR part 60, subpart A, 

Table 1: Detection Sensitivity Levels; 

§ 60.18(i)(2)(ii) and (iii) except the gas 

chosen shall be methane, and 

§ 60.18(i)(2)(iv) and (v); § 60.18(i)(3); 

§ 60.18(i)(4)(i) and (v); including the 

requirements for daily instrument 

checks and distances, and excluding 

requirements for video records. Any 

emissions detected by the optical gas 

imaging instrument from an applicable 

component is a leak. In addition, you 

must operate the optical gas imaging 

instrument to image the source types 

required by this subpart in accordance 

with the instrument manufacturer’s 

operating parameters. 

(ii) Optical gas imaging instrument as 

specified in § 60.5397a of this chapter. 

Use an optical gas imaging instrument 

for equipment leak detection in 

accordance with § 60.5397a(b), (c)(3) 

and (7), and (e) of this chapter and 

paragraphs (a)(1)(ii)(A) through (C) of 

this section. 

(A) For the purposes of this subpart, 

any visible emissions observed by the 

optical gas imaging instrument from a 

component required or elected to be 

monitored as specified in § 98.233(q)(1) 

is a leak. 

(B) For the purposes of this subpart, 

the term ‘‘fugitive emissions 

component’’ in § 60.5397a of this 

chapter means ‘‘component.’’ 

(C) For the purpose of complying with 

§ 98.233(q)(1)(iv), the phrase ‘‘the 

collection of fugitive emissions 

components at well sites and 

compressor stations’’ in § 60.5397a(b) of 

this chapter means ‘‘the collection of 

components for which you elect to 

comply with § 98.233(q)(1)(iv).’’ 

(iii) Optical gas imaging instrument as 

specified in appendix K to part 60 of 

this chapter. Use an optical gas imaging 

instrument for equipment leak detection 

in accordance with appendix K to part 

60, Determination of Volatile Organic 

Compound and Greenhouse Gas Leaks 

Using Optical Gas Imaging. Any 

emissions detected by the optical gas 

imaging instrument from an applicable 

component is a leak. 

(2) Method 21. Use the equipment 

leak detection methods in Method 21 in 

appendix A–7 to part 60 of this chapter 

as specified in paragraph (a)(2)(i) or (ii) 

of this section. You may use either of 

the methods as specified in paragraphs 

(a)(2)(i) and (ii) of this section unless 

you are required to use a specific 

method to comply with the fugitive 

emission component requirements in 

part 60, subpart OOOOa of this chapter 

or with the fugitive emission component 

or equipment leak requirements in part 

60, subpart OOOOb of this chapter or 

with the fugitive emission component or 

equipment leak requirements in an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter. You must survey all 

applicable source types at the facility 

needed to conduct a complete 

equipment leak survey as defined in 

§ 98.233(q)(1). For the purposes of this 

subpart, the term ‘‘fugitive emissions 

component’’ in § 60.5397a of this 

chapter means ‘‘component.’’ 

(i) Method 21 with a leak definition of 

10,000 ppm. Use the equipment leak 

detection methods in Method 21 in 

appendix A–7 to part 60 of this chapter 

using methane as the reference 

compound. If an instrument reading of 

10,000 ppm or greater is measured for 

any applicable component, a leak is 

detected. 

(ii) Method 21 with a leak definition 

of 500 ppm. Use the equipment leak 

detection methods in Method 21 in 

appendix A–7 to part 60 of this chapter 

using methane as the reference 

compound. If an instrument reading of 

500 ppm or greater is measured for any 

applicable component, a leak is 

detected. 

(3) Infrared laser beam illuminated 

instrument. Use an infrared laser beam 

illuminated instrument for equipment 

leak detection. Any emissions detected 

by the infrared laser beam illuminated 

instrument is a leak. In addition, you 

must operate the infrared laser beam 

illuminated instrument to detect the 

source types required by this subpart in 

accordance with the instrument 

manufacturer’s operating parameters. 

(4) [Reserved] 

(5) Acoustic leak detection device. 

Use the acoustic leak detection device to 

detect through-valve leakage. When 

using the acoustic leak detection device 

to quantify the through-valve leakage, 

you must use the instrument 

manufacturer’s calculation methods to 

quantify the through-valve leak. When 

using the acoustic leak detection device, 

if a leak of 3.1 scf per hour or greater 

is calculated, a leak is detected. In 

addition, you must operate the acoustic 

leak detection device to monitor the 

source valves required by this subpart in 

accordance with the instrument 

manufacturer’s operating parameters. 

Acoustic stethoscope type devices 

designed to detect through valve leakage 

when put in contact with the valve body 

and that provide an audible leak signal 

but do not calculate a leak rate can be 

used to identify through-valve leakage. 

For these acoustic stethoscope type 

devices, a leak is detected if an audible 

leak signal is observed or registered by 

the device. If the acoustic stethoscope 

type device is used as a screening to a 

measurement method and a leak is 

detected, the leak must be measured 

using any one of the methods specified 

in paragraphs (b) through (d) of this 

section. 

* * * * * 

(d) * * * 

(3) For high volume samplers that 

output methane mass emissions, you 

must use the calculations in § 98.233(u) 

and (v) in reverse to determine the 

natural gas volumetric emissions at 

standard conditions. For high volume 

samplers that output methane 

volumetric flow in actual conditions, 

divide the volumetric methane flow rate 

by the mole fraction of methane in the 

natural gas according to the provisions 

in § 98.233(u) and estimate natural gas 

volumetric emissions at standard 

conditions using calculations in 

§ 98.233(t). Estimate CH4 and CO2

volumetric and mass emissions from 

volumetric natural gas emissions using 

the calculations in § 98.233(u) and (v). 

* * * * * 

(5) If the measured methane flow 

exceeds the manufacturer’s reported 

quantitation limit or if the measured 

natural gas flow determined as specified 

in paragraph (d)(3) of this section 

exceeds 70 percent of the 

manufacturer’s reported maximum 

sampling flow rate, then the flow 

exceeds the capacity of the instrument 

and you must either use a temporary or 

permanent flow meter according to 

paragraph (b) of this section or use 

calibrated bags according to paragraph 

(c) of this section to determine the leak 

or flow rate. 

* * * * * 

(i) Special reporting provisions for 

best available monitoring methods in 

reporting year 2023—(1) Use of best 

available monitoring methods. From 

January 1, 2023, to December 31, 2023, 

you must use the calculation 

methodologies and equations in 

§ 98.233 but you may use the best 

available monitoring method as 

described in paragraph (i)(2) of this 

section for any parameter specified in 

paragraphs (i)(3) through (7) of this 

section for which it is not reasonably 

feasible to acquire, install, and operate 

a required piece of monitoring 

equipment by January 1, 2023. Starting 

no later than January 1, 2024, you must 

discontinue using best available 

methods and begin following all 

applicable monitoring and QA/QC 

requirements of this part. 

(2) Best available monitoring 

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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 facility records. 

(3) Best available monitoring methods 

for measurement data for natural gas 

pneumatic devices. You may use best 

available monitoring methods for any 

measurement data, including activity 

data such as gas compositions and hours 

of operation, that cannot reasonably be 

measured according to the monitoring 

and QA/QC requirements of this subpart 

for natural gas pneumatic devices as 

specified in § 98.233(a) at onshore 

natural gas processing plants and for 

natural gas intermittent bleed 

pneumatic devices that are monitored as 

specified in § 98.233(a)(6). 

(4) Best available monitoring methods 

for measurement data for LNG import/ 

export facilities. You may use best 

available monitoring methods for any 

measurement data, including activity 

data such as flow rates, gas 

compositions, and hours of operation, 

that cannot reasonably be measured 

according to the monitoring and QA/QC 

requirements of this subpart for acid gas 

removal vents as specified in § 98.233(d) 

at LNG import/export facilities. 

(5) Best available monitoring methods 

for measurement data for other large 

release events. You may use best 

available monitoring methods for any 

measurement data, including activity 

data such as flow rates, gas 

compositions, and hours of operation, 

that cannot reasonably be measured 

according to the monitoring and QA/QC 

requirements of this subpart for other 

large release events as specified in 

§ 98.233(y). 

(6) Best available monitoring methods 

for measurement data for miscellaneous 

flared sources. You may use best 

available monitoring methods for any 

measurement data, including activity 

data such as flow rates and gas 

compositions, that cannot reasonably be 

obtained according to the monitoring 

and QA/QC requirements of this subpart 

for miscellaneous flared sources as 

specified in § 98.233(n)(1) and (2). 

(7) Best available monitoring methods 

for measurement data for specific 

emission sources routed to vapor 

recovery. You may use best available 

monitoring methods for any 

measurement data, including activity 

data such as flow rates, gas 

compositions, and hours of operation, 

that cannot reasonably be obtained 

according to the monitoring and QA/QC 

requirements of this subpart for 

dehydrator vents and storage tank vents 

routed to vapor recovery as specified in 

§ 98.233(e)(4) and (j)(4), respectively. 

(8) Best available monitoring methods 

for measurement data for compressors. 

You may use best available monitoring 

methods for any measurement data that 

cannot reasonably be obtained 

according to the monitoring and QA/QC 

requirements of this subpart for dry seal 

vents on centrifugal compressors and all 

compressor sources for centrifugal 

compressors found in standbypressurized-mode as specified in 

§ 98.233(o). You may use best available 

monitoring methods for any 

measurement data that cannot 

reasonably be obtained according to the 

monitoring and QA/QC requirements of 

this subpart for rod packing on 

reciprocating compressors in standbypressurized-mode as specified in 

§ 98.233(p). 

(9) Best available monitoring methods 

for measurement data for a facility that 

was part of a facility with respect to 

onshore petroleum and natural gas 

gathering and boosting prior to January 

1, 2023, and meets the definition of 

onshore natural gas processing in 

§ 98.230(a)(3) effective as of January 1, 

2023. You may use best available 

monitoring methods for measurement 

data, including activity data, as listed in 

paragraphs (i)(9)(i) through (iv) of this 

section that cannot reasonably be 

obtained according to the monitoring 

and QA/QC requirements of this 

subpart. 

(i) Temperature and pressure for 

emergency blowdowns in § 98.233(i). 

(ii) Equipment leak surveys in 

§ 98.233(q). 

(iii) Centrifugal compressors in 

§ 98.233(o). 

(iv) Reciprocating compressors in 

§ 98.233(p). 

(10) Best available monitoring 

methods for measurement data for a 

facility that was an onshore natural gas 

processing facility prior to January 1, 

2023, and became part of a facility with 

respect to onshore petroleum and 

natural gas gathering and boosting as 

defined in § 98.238 as of January 1, 

2023, due to the change in definition of 

onshore natural gas processing in 

§ 98.230(a)(3) effective as of January 1, 

2023. You may use best available 

monitoring methods for measurement 

data, including activity data, as listed in 

paragraphs (i)(10)(i) through (iii) of this 

section that cannot reasonably be 

obtained according to the monitoring 

and QA/QC requirements of this 

subpart. 

(i) Natural gas driven pneumatic 

pumps in § 98.233(c). 

(ii) Storage tanks in § 98.233(j). 

(iii) Equipment leak surveys in 

§ 98.233(q) and/or equipment leaks by 

population count in § 98.233(r), as 

applicable, for equipment components 

not required for the onshore natural gas 

processing industry segment (i.e., 

pumps, flanges, other components, and 

gathering pipelines). 

■ 59. Amend § 98.236 by: 

■ a. Revising the introductory text and 

paragraphs (a)(1) introductory text and 

(a)(1)(xviii); 

■ b. Adding paragraph (a)(1)(xix); 

■ c. Revising paragraphs (a)(2) and (a)(3) 

introductory text; 

■ d. Redesignating paragraphs (a)(3)(i) 

through (vii) as paragraphs (a)(3)(ii) 

through (viii), respectively; 

■ e. Adding new paragraph (a)(3)(i) and 

paragraph (a)(3)(ix); 

■ f. Revising paragraph (a)(4) 

introductory text; 

■ g. Adding paragraph (a)(4)(viii); 

■ h. Revising paragraph (a)(5) 

introductory text; 

■ i. Adding paragraph (a)(5)(vii); 

■ j. Revising paragraph (a)(6) 

introductory text; 

■ k. Adding paragraph (a)(6)(vi); 

■ l. Revising paragraph (a)(7) 

introductory text; 

■ m. Redesignating paragraphs (a)(7)(i) 

through (vi) as paragraphs (a)(7)(ii) 

through (vii), respectively; 

■ n. Adding new paragraph (a)(7)(i) and 

paragraph (a)(7)(viii); 

■ o. Revising paragraph (a)(8) 

introductory text; 

■ p. Adding paragraph (a)(8)(iv); 

■ q. Revising paragraphs (a)(9) 

introductory text and (a)(9)(xii); 

■ r. Adding paragraph (a)(9)(xiii); 

■ s. Revising paragraphs (a)(10), (b), (c), 

(d)(1)(iii), and (d)(2)(iii)(L); 

■ t. Adding paragraph (d)(2)(iv); 

■ u. Revising paragraphs (e) 

introductory text, (e)(1) introductory 

text, and (e)(1)(viii), (xi), (xii), and (xv) 

through (xviii); 

■ v. Adding paragraph (e)(1)(xix); 

■ w. Revising paragraph (e)(2); 

■ x. Removing and reserving paragraph 

(e)(3); 

■ y. Revising paragraphs (f)(1) 

introductory text and (f)(1)(iii); 

■ z. Adding paragraphs (f)(1)(xi)(F) and 

(f)(1)(xii)(F); 

■ aa. Revising paragraphs (f)(2) 

introductory text and (f)(2)(iii), (ix) and 

(x); 

■ bb. Adding paragraphs (f)(2)(xi) and 

(xii); 

■ cc. Revising paragraphs (g)(10), (h)(2) 

introductory text, and (h)(2)(v) through 

(vii); 

■ dd. Adding paragraphs (h)(2)(viii) 

through (xvi); 

■ ee. Revising paragraphs (h)(4) 

introductory text and (h)(4)(iii) through 

(v); 


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■ ff. Adding paragraphs (h)(4)(vi) 

through (xiv); 

■ gg. Revising paragraphs (i)(1) 

introductory text, (j) introductory text, 

(j)(1) and (2), (j)(3)(ii), (k)(1)(ii) through 

(iv), (k)(2) introductory text, (k)(3), (l)(1) 

introductory text, (l)(2) introductory 

text, and (l)(2)(vi) through (viii); 

■ hh. Adding paragraphs (l)(2)(ix) 

through (xvii); 

■ ii. Revising paragraphs (l)(3) 

introductory text, (l)(4) introductory 

text, and (l)(4)(v) through (vii); 

■ jj. Adding paragraphs (l)(4)(viii) 

through (xvi); 

■ kk. Revising paragraphs (m)(4) 

through (8), (n), (o)(1), (o)(2)(i)(B), 

(o)(2)(ii)(A), (o)(5)(i) through (iii), (p)(1), 

(p)(2)(ii)(A), (p)(3)(ii) introductory text, 

(p)(5)(i) through (iii), (q)(1) introductory 

text, and (q)(1)(iii); 

■ ll. Adding paragraphs (q)(1)(vi) and 

(vii); 

■ mm. Revising paragraphs (q)(2), (r)(1) 

introductory text, and (r)(1)(i); 

■ nn. Removing and reserving 

paragraph (r)(3); 

■ oo. Revising paragraphs (s) 

introductory text, (y), (z) introductory 

text, (z)(2)(i) and (iv) through (vi), (aa)(3) 

introductory text, and (aa)(3)(i); 

■ pp. Adding paragraph (aa)(3)(viii); 

■ qq. Removing and reserving paragraph 

(aa)(9); 

■ rr. Revising paragraph (aa)(10) 

introductory text; 

■ ss. Adding paragraphs (aa)(10)(v) and 

(vi); and 

■ tt. Revising paragraphs (aa)(11)(ii) and 

(iii), (bb) introductory text, and (cc). 

The revisions and additions read as 

follows: 

§ 98.236 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain reported emissions and 

related information as specified in this 

section. Reporters that use a flow or 

volume measurement system that 

corrects to standard conditions as 

provided in the introductory text in 

§ 98.233 for data elements that are 

otherwise required to be determined at 

actual conditions, report gas volumes at 

standard conditions rather than the gas 

volumes at actual conditions and report 

the standard temperature and pressure 

used by the measurement system rather 

than the actual temperature and 

pressure. 

(a) * * * 

(1) Onshore petroleum and natural 

gas production. For the equipment/ 

activities specified in paragraphs 

(a)(1)(i) through (xix) of this section, 

report the information specified in the 

applicable paragraphs of this section. 

* * * * * 

(xviii) Other large release events. 

Report the information specified in 

paragraph (y) of this section. 

(xix) Combustion equipment. Report 

the information specified in paragraph 

(z) of this section. 

(2) Offshore petroleum and natural 

gas production. Report the information 

specified in paragraphs (s) and (y) of 

this section. 

(3) Onshore natural gas processing. 

For the equipment/activities specified 

in paragraphs (a)(3)(i) through (ix) of 

this section, report the information 

specified in the applicable paragraphs of 

this section. 

(i) Natural gas pneumatic devices. 

Report the information specified in 

paragraph (b) of this section. 

* * * * * 

(ix) Other large release events. Report 

the information specified in paragraph 

(y) of this section. 

(4) Onshore natural gas transmission 

compression. For the equipment/ 

activities specified in paragraphs 

(a)(4)(i) through (viii) of this section, 

report the information specified in the 

applicable paragraphs of this section. 

* * * * * 

(viii) Other large release events. 

Report the information specified in 

paragraph (y) of this section. 

(5) Underground natural gas storage. 

For the equipment/activities specified 

in paragraphs (a)(5)(i) through (vii) of 

this section, report the information 

specified in the applicable paragraphs of 

this section. 

* * * * * 

(vii) Other large release events. Report 

the information specified in paragraph 

(y) of this section. 

(6) LNG storage. For the equipment/ 

activities specified in paragraphs 

(a)(6)(i) through (vi) of this section, 

report the information specified in the 

applicable paragraphs of this section. 

* * * * * 

(vi) Other large release events. Report 

the information specified in paragraph 

(y) of this section. 

(7) LNG import and export equipment. 

For the equipment/activities specified 

in paragraphs (a)(7)(i) through (viii) of 

this section, report the information 

specified in the applicable paragraphs of 

this section. 

(i) Acid gas removal units. Report the 

information specified in paragraph (d) 

of this section. 

* * * * * 

(viii) Other large release events. 

Report the information specified in 

paragraph (y) of this section. 

(8) Natural gas distribution. For the 

equipment/activities specified in 

paragraphs (a)(8)(i) through (iv) of this 

section, report the information specified 

in the applicable paragraphs of this 

section. 

* * * * * 

(iv) Other large release events. Report 

the information specified in paragraph 

(y) of this section. 

(9) Onshore petroleum and natural 

gas gathering and boosting. For the 

equipment/activities specified in 

paragraphs (a)(9)(i) through (xiii) of this 

section, report the information specified 

in the applicable paragraphs of this 

section. 

* * * * * 

(xii) Other large release events. Report 

the information specified in paragraph 

(y) of this section. 

(xiii) Combustion equipment. Report 

the information specified in paragraph 

(z) of this section. 

(10) Onshore natural gas transmission 

pipeline. For blowdown vent stacks, 

report the information specified in 

paragraphs (i) and (y) of this section. 

(b) Natural gas pneumatic devices. 

You must indicate whether the facility 

contains the following types of 

equipment: Continuous high bleed 

natural gas pneumatic devices, 

continuous low bleed natural gas 

pneumatic devices, and intermittent 

bleed natural gas pneumatic devices. If 

the facility contains any continuous 

high bleed natural gas pneumatic 

devices, continuous low bleed natural 

gas pneumatic devices, or intermittent 

bleed natural gas pneumatic devices, 

then you must report the information 

specified in paragraphs (b)(1) through 

(4) of this section. 

(1) The number of natural gas 

pneumatic devices as specified in 

paragraphs (b)(1)(i) through (iii) of this 

section. 

(i) For onshore natural gas processing, 

onshore natural gas transmission 

compression, and underground natural 

gas storage facilities, the total number of 

devices of each type (continuous low 

bleed, continuous high bleed, and 

intermittent bleed), determined 

according to § 98.233(a)(2). 

(ii) For onshore petroleum and natural 

gas production and onshore petroleum 

and natural gas gathering and boosting 

facilities, the number of devices by each 

type as specified in paragraphs 

(b)(1)(ii)(A) through (E) of this section. 

(A) Continuous low bleed devices. 

(B) Continuous high bleed devices. 

(C) Intermittent bleed devices subject 

to part 60, subpart OOOOb of this 

chapter or an applicable approved state 

plan or applicable Federal plan in part 

62 of this chapter (i.e., the number 

required to use Equation W–1B). 

(D) Intermittent bleed devices not 

subject to part 60, subpart OOOOb of 


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this chapter or an applicable approved 

state plan or applicable Federal plan in 

part 62 of this chapter but routinely 

monitored (i.e., the number electing to 

use Equation W–1B). 

(E) Intermittent bleed devices not 

subject to part 60, subpart OOOOb of 

this chapter or an applicable approved 

state plan or applicable Federal plan in 

part 62 of this chapter and not routinely 

monitored (i.e., the number using 

Equation W–1A). 

(iii) If the reported values in 

paragraphs (b)(1)(ii)(A), (B), and (E) of 

this section are estimated values 

determined according to § 98.233(a)(3), 

then you must report the information 

specified in paragraphs (b)(1)(iii)(A) 

through (C) of this section. 

(A) The number of devices of each 

type reported in paragraphs (b)(1)(ii)(A), 

(B), and (E) of this section that are 

counted. 

(B) The number of devices of each 

type reported in paragraphs (b)(1)(ii)(A), 

(B), and (E) of this section that are 

estimated (not counted). 

(C) Whether the calendar year is the 

first calendar year of reporting or the 

second calendar year of reporting. 

(2) For each type of pneumatic device 

for which Equation W–1A of this 

subpart is used, report the information 

in paragraphs (b)(2)(i) through (iii) of 

this section. 

(i) The estimated average number of 

hours in the calendar year that the 

natural gas pneumatic devices reported 

in paragraph (b)(1)(i) or paragraphs 

(b)(1)(ii)(A), (B), and (E) of this section, 

as applicable, were in service (i.e., 

supplied with natural gas) in the 

calendar year (‘‘Tt’’ in Equation W–1A 

of this subpart). 

(ii) Annual CO2 emissions, in metric 

tons CO2, for the natural gas pneumatic 

devices combined, calculated using 

Equation W–1A of this subpart and 

§ 98.233(a)(5), and reported in 

paragraph (b)(1)(i) or paragraphs 

(b)(1)(ii)(A), (B), and (E) of this section, 

as applicable. 

(iii) Annual CH4 emissions, in metric 

tons CH4, for the natural gas pneumatic 

devices combined, calculated using 

Equation W–1A of this subpart and 

§ 98.233(a)(5), and reported in 

paragraph (b)(1)(i) or paragraphs 

(b)(1)(ii)(A), (B), and (E) of this section, 

as applicable. 

(3) For intermittent bleed pneumatic 

devices for which Equation W–1B of 

this subpart is used, report the 

information in paragraphs (b)(3)(i) 

through (iii) of this section. 

(i) The total number of intermittent 

devices detected as malfunctioning in 

any pneumatic device monitoring 

survey during the calendar year (‘‘x’’ in 

Equation W–1B of this subpart). 

(ii) Average time the intermittent 

devices were in service (i.e., supplied 

with natural gas) and assumed to be 

malfunctioning in the calendar year 

(average value of ‘‘Tz’’ in Equation W– 

1B of this subpart). 

(iii) The total number of intermittent 

devices that were monitored but were 

not detected as malfunctioning in any 

pneumatic device monitoring survey 

during the calendar year (‘‘Count’’ in 

Equation W–1B of this subpart). 

(iv) Average time the intermittent 

devices that were monitored but were 

not detected as malfunctioning in any 

pneumatic device monitoring survey 

during the calendar year were in service 

(i.e., supplied with natural gas) during 

the calendar year (‘‘Tavg’’ in Equation 

W–1B of this subpart). 

(v) Annual CO2 emissions, in metric 

tons CO2, for the natural gas intermittent 

bleed pneumatic devices combined for 

which emissions were calculated using 

Equation W–1B of this subpart and 

§ 98.233(a)(6). 

(vi) Annual CH4 emissions, in metric 

tons CH4, for the natural gas pneumatic 

devices combined for which emissions 

were calculated using Equation W–1B of 

this subpart and § 98.233(a)(6). 

(c) Natural gas driven pneumatic 

pumps. You must indicate whether the 

facility has any natural gas driven 

pneumatic pumps. If the facility 

contains any natural gas driven 

pneumatic pumps, then you must report 

the information specified in paragraphs 

(c)(1) through (6) of this section. If a 

pump was vented directly to the 

atmosphere for part of the year and 

routed to a flare, combustion, or vapor 

recovery system during another part of 

the year, then include the pump in each 

of the counts specified in paragraphs 

(c)(1) through (3) of this section. 

(1) Count of natural gas driven 

pneumatic pumps vented directly to the 

atmosphere at any point during the year. 

(2) Count of natural gas driven 

pneumatic pumps routed to a flare, 

combustion, or vapor recovery system at 

any point during the year. 

(3) Total count of natural gas driven 

pneumatic pumps at the facility. 

(4) Average estimated number of 

hours in the calendar year that natural 

gas driven pneumatic pumps that 

vented directly to atmosphere were in 

service (i.e., supplied with natural gas) 

(‘‘T’’ in Equation W–2 of this subpart). 

(5) Annual CO2 emissions, in metric 

tons CO2, for all natural gas driven 

pneumatic pumps vented directly to the 

atmosphere combined, calculated 

according to § 98.233(c)(1) and (2). 

(6) Annual CH4 emissions, in metric 

tons CH4, for all natural gas driven 

pneumatic pumps vented directly to the 

atmosphere combined, calculated 

according to § 98.233(c)(1) and (2). 

(d) * * * 

(1) * * * 

(iii) The calculation method used to 

calculate CO2 emissions from the acid 

gas removal unit, as specified in 

§ 98.233(d). If the AGR vent was routed 

to a flare and comingled with emissions 

from other sources and you 

continuously monitor the flow rate and/ 

or composition, select ‘‘Routed to a flare 

[§ 98.233(d)(12)(ii)]’’ as the calculation 

method. 

* * * * * 

(2) * * * 

(iii) * * * 

(L) Solvent type, from one of the 

following options: SelexolTM, Rectisol®, 

PurisolTM, Fluor SolventSM, BenfieldTM, 

20 wt% MEA, 30 wt% MEA, 40 wt% 

MDEA, 50 wt% MDEA, and other. 

(iv) If the AGR vent was routed to a 

flare, then you must report the unique 

name or ID for the flare stack to which 

the AGR vent is routed. 

(e) Dehydrators. You must indicate 

whether your facility contains any of the 

following equipment: Glycol 

dehydrators with an annual average 

daily natural gas throughput greater 

than or equal to 0.4 million standard 

cubic feet per day and glycol 

dehydrators with an annual average 

daily natural gas throughput less than 

0.4 million standard cubic feet per day. 

If your facility contains any of the 

equipment listed in this paragraph (e), 

then you must report the applicable 

information in paragraphs (e)(1) through 

(3) of this section. 

(1) For each glycol dehydrator that 

has an annual average daily natural gas 

throughput greater than or equal to 0.4 

million standard cubic feet per day (as 

specified in § 98.233(e)(1)), you must 

report the information specified in 

paragraphs (e)(1)(i) through (xix) of this 

section for the dehydrator. 

* * * * * 

(viii) Whether stripping gas is used in 

dehydrator. 

(A) If stripping gas is used in the 

dehydrator, type of stripping gas used 

(dry natural gas, flash gas, nitrogen/inert 

gas, other). 

(B) If stripping gas is used in the 

dehydrator, average flow rate of 

stripping gas in standard cubic feet per 

minute. 

* * * * * 

(xi) Temperature of the wet natural 

gas at the absorber inlet, in degrees 

Fahrenheit. 


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(xii) Pressure of the wet natural gas at 

the absorber inlet, in pounds per square 

inch gauge. 

* * * * * 

(xv) Sub-basin ID that best represents 

the wells supplying gas to the 

dehydrator (for the onshore petroleum 

and natural gas production industry 

segment only) or name of the county 

that best represents the equipment 

supplying gas to the dehydrator (for the 

onshore petroleum and natural gas 

gathering and boosting industry segment 

only). 

(xvi) If a flash tank separator is used 

in the dehydrator, then you must report 

the information specified in paragraphs 

(e)(1)(xvi)(A) through (I) of this section 

for the emissions from the flash tank 

vent. 

(A) Flash tank vent gas flow rate in 

standard cubic feet per hour. 

(B) Flow-weighted average mole 

fraction of CO2 in flash tank vent gas 

(‘‘XCO2’’ in Equation W–20 of this 

subpart if the flash tank vent gas is 

routed to a flare). 

(C) Flow-weighted average mole 

fraction of CH4 in flash tank vent gas 

(‘‘XCH4’’ in Equation W–19 of this 

subpart if the flash tank vent gas is 

routed to a flare). 

(D) Whether any flash gas emissions 

are vented directly to the atmosphere, 

routed to a flare, routed to the 

regenerator firebox/fire tubes, routed to 

a vapor recovery system, used as 

stripping gas, or any combination. 

(E) Annual CO2 emissions, in metric 

tons CO2, from the flash tank when not 

routed to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(1)(iv), and, if applicable, 

(e)(1)(vi)(A). 

(F) Annual CH4 emissions, in metric 

tons CH4, from the flash tank when not 

routed to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(1)(iv) and, if applicable, 

(e)(1)(vi)(A). 

(G) Annual CO2 emissions, in metric 

tons CO2, that resulted from routing 

flash gas to a flare or regenerator 

firebox/fire tubes, calculated according 

to § 98.233(e)(1)(v) and, if applicable, 

(e)(1)(vi)(B). 

(H) Annual CH4 emissions, in metric 

tons CH4, that resulted from routing 

flash gas to a flare or regenerator 

firebox/fire tubes, calculated according 

to § 98.233(e)(1)(v) and, if applicable, 

(e)(1)(vi)(B). 

(I) Annual N2O emissions, in metric 

tons N2O, that resulted from routing 

flash gas to a flare or regenerator 

firebox/fire tubes, calculated according 

to § 98.233(e)(1)(v) and, if applicable, 

(e)(1)(vi)(B). 

(xvii) If flash tank emissions were 

routed to a flare, then you must report 

the information specified in paragraphs 

(e)(1)(xvii)(A) through (G) of this section 

for the flared emissions from the flash 

tank vent. 

(A) Indicate whether the flare was 

monitored with a CEMS in accordance 

with § 98.233(n)(8). If a CEMS was used, 

then paragraphs (e)(1)(xvi)(H) and (I) 

and (e)(1)(xvii)(B) through (G) of this 

section do not apply. 

(B) Indicate whether all gas from the 

flash tank was measured using a 

continuous flow monitor. 

(C) Indicate whether all gas from the 

flash tank was measured with a 

continuous gas composition analyzer. 

(D) Indicate whether only the default 

HHV, only a site-specific HHV(s), or 

both the default and site-specific HHVs 

(depending on the stream to the flare) 

were used in Equation W–40 to 

calculate N2O emissions. 

(E) Total volume of gas from the flash 

tank to a flare, in standard cubic feet 

(‘‘Vs’’ in Equations W–19 and W–20 of 

this subpart). 

(F) Fraction of total flared gas from 

the flash tank routed to an un-lit flare 

(‘‘Zu’’ in Equation W–19 of this subpart). 

(G) Average flare combustion 

efficiency, expressed as a fraction of gas 

from the flash tank combusted by a 

burning flare. 

(xviii) Report the information 

specified in paragraphs (e)(1)(xviii)(A) 

through (I) of this section for the 

emissions from the dehydrator still vent. 

(A) Still vent gas flow rate in standard 

cubic feet per hour. 

(B) Flow-weighted average mole 

fraction of CO2 in still vent gas (‘‘XCO2’’ 

in Equation W–20 of this subpart if the 

flash tank vent gas is routed to a flare). 

(C) Flow-weighted average mole 

fraction of CH4 in still vent gas (‘‘XCH4’’ 

in Equation W–19 of this subpart if the 

flash tank vent gas is routed to a flare). 

(D) Whether any still vent emissions 

are vented directly to the atmosphere, 

routed to a flare, routed to the 

regenerator firebox/fire tubes, or routed 

to a vapor recovery system. 

(E) Annual CO2 emissions, in metric 

tons CO2, from the still vent when not 

routed to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(1)(iv), and, if applicable, 

(e)(1)(vi)(A). 

(F) Annual CH4 emissions, in metric 

tons CH4, from the still vent when not 

routed to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(1)(iv) and, if applicable, 

(e)(1)(vi)(A). 

(G) Annual CO2 emissions, in metric 

tons CO2, that resulted from routing still 

vent gas to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(1)(v) and, if applicable, 

(e)(1)(vi)(B). 

(H) Annual CH4 emissions, in metric 

tons CH4, that resulted from routing still 

vent gas to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(1)(v) and, if applicable, 

(e)(1)(vi)(B). 

(I) Annual N2O emissions, in metric 

tons N2O, that resulted from routing still 

vent gas to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(1)(v) and, if applicable, 

(e)(1)(vi)(B). 

(xix) If emissions from the still vent 

were routed to a flare, then you must 

report the information specified in 

paragraphs (e)(1)(xix)(A) through (G) of 

this section for the flared emissions 

from the still vent. 

(A) Indicate whether the flare was 

monitored with a CEMS in accordance 

with § 98.233(n)(8). If a CEMS was used, 

then paragraphs (e)(1)(xviii)(H) and (I) 

and (e)(1)(xix)(B) through (G) of this 

section do not apply. 

(B) Indicate whether all gas from the 

still vent was measured using a 

continuous flow monitor. 

(C) Indicate whether all gas from the 

still vent was measured with a 

continuous gas composition analyzer. 

(D) Indicate whether only the default 

HHV, only a site-specific HHV(s), or 

both the default and site-specific HHVs 

(depending on the stream to the flare) 

were used in Equation W–40 to 

calculate N2O emissions. 

(E) Total volume of gas from the still 

vent to a flare, in standard cubic feet 

(‘‘Vs’’ in Equations W–19 and W–20 of 

this subpart). 

(F) Fraction of total flared gas from 

the still vent routed to an un-lit flare 

(‘‘Zu’’ in Equation W–19 of this subpart). 

(G) Average flare combustion 

efficiency, expressed as a fraction of gas 

from the still vent combusted by a 

burning flare. 

(2) You must report the information 

specified in paragraphs (e)(2)(i) through 

(v) of this section for all glycol 

dehydrators with an annual average 

daily natural gas throughput greater 

than 0 million standard cubic feet per 

day and less than 0.4 million standard 

cubic feet per day (as specified in 

§ 98.233(e)(2)) at the facility. 

(i) The total number of dehydrators at 

the facility. 

(ii) Whether any dehydrator emissions 

were routed to a vapor recovery system. 

If any dehydrator emissions were routed 

to a vapor recovery system, then you 

must report the total number of 

dehydrators at the facility that routed to 

a vapor recovery system. 


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(iii) Whether any dehydrator 

emissions were routed to a control 

device other than a vapor recovery 

system or a flare or regenerator firebox/ 

fire tubes. If any dehydrator emissions 

were routed to a control device(s) other 

than a vapor recovery system or a flare 

or regenerator firebox/fire tubes, then 

you must specify the type of control 

device(s) and the total number of 

dehydrators at the facility that were 

routed to each type of control device. 

(iv) Whether any dehydrator 

emissions were routed to a flare or 

regenerator firebox/fire tubes. If any 

dehydrator emissions were routed to a 

flare or regenerator firebox/fire tubes, 

then you must report the information 

specified in paragraphs (e)(2)(iv)(A) 

through (L) of this section. 

(A) The total number of dehydrators 

routed to a flare or regenerator firebox/ 

fire tubes. 

(B) Indicate whether all gas from the 

dehydrators routed to flares was 

measured using a continuous flow 

monitor. 

(C) Indicate whether all gas from the 

dehydrators routed to flares was 

measured with a continuous gas 

composition analyzer. 

(D) Indicate whether only the default 

HHV, only a site-specific HHV(s), or 

both the default and site-specific HHVs 

(depending on the stream to the flare) 

were used in Equation W–40 to 

calculate N2O emissions. 

(E) Total volume of gas from 

dehydrators to a flare, in standard cubic 

feet (‘‘Vs’’ in Equations W–19 and W–20 

of this subpart). 

(F) Fraction of total flared gas from 

the dehydrators routed to un-lit flares 

(‘‘Zu’’ in Equation W–19 of this subpart). 

(G) Average flare combustion 

efficiency, expressed as a fraction of gas 

from the dehydrators combusted by a 

burning flare. 

(H) Flow-weighted average mole 

fraction of CH4 in gas from the 

dehydrators routed to a flare (‘‘XCH4’’ in 

Equation W–19 of this subpart). 

(I) Flow-weighted average mole 

fraction of CO2 in gas from the 

dehydrators routed to a flare (‘‘XCO2’’ in 

Equation W–20 of this subpart). 

(J) Annual CO2 emissions, in metric 

tons CO2, for the dehydrators reported 

in paragraph (e)(2)(iv)(A) of this section, 

calculated according to § 98.233(e)(5) 

and, if applicable, (e)(4)(ii). 

(K) Annual CH4 emissions, in metric 

tons CH4, for the dehydrators reported 

in paragraph (e)(2)(iv)(A) of this section, 

calculated according to § 98.233(e)(5) 

and, if applicable, (e)(4)(ii). 

(L) Annual N2O emissions, in metric 

tons N2O, for the dehydrators reported 

in paragraph (e)(2)(iv)(A) of this section, 

calculated according to § 98.233(e)(5) 

and, if applicable, (e)(4)(ii). 

(v) For dehydrator emissions that 

were not routed to a flare or regenerator 

firebox/fire tubes, report the information 

specified in paragraphs (e)(2)(v)(A) and 

(B) of this section. 

(A) Annual CO2 emissions, in metric 

tons CO2, for emissions from all 

dehydrators reported in paragraph 

(e)(2)(i) of this section that were not 

routed to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(2) and, if applicable, (e)(4)(i), 

where emissions are added together for 

all such dehydrators. 

(B) Annual CH4 emissions, in metric 

tons CH4, for emissions from all 

dehydrators reported in paragraph 

(e)(2)(i) of this section that were not 

routed to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(2) and, if applicable, (e)(4)(i), 

where emissions are added together for 

all such dehydrators. 

* * * * * 

(f) * * * 

(1) For each sub-basin and well tubing 

diameter and pressure group for which 

you used Calculation Method 1 to 

calculate natural gas emissions from 

well venting for liquids unloading, 

report the information specified in 

paragraphs (f)(1)(i) through (xii) of this 

section. Report information separately 

for wells by unloading type 

combination. 

* * * * * 

(iii) Unloading type combination 

(with or without plunger lifts, 

automated or manual unloading). 

* * * * * 

(xi) * * * 

(F) Unloading type (automated or 

manual). 

(xii) * * * 

(F) Unloading type (automated or 

manual). 

(2) For each sub-basin for which you 

used Calculation Method 2 or 3 (as 

specified in § 93.233(f)) to calculate 

natural gas emissions from well venting 

for liquids unloading, you must report 

the information in paragraphs (f)(2)(i) 

through (xii) of this section. Report 

information separately for each 

calculation method and unloading type 

combination. 

* * * * * 

(iii) Unloading type combination 

(with or without plunger lifts, 

automated or manual unloadings). 

* * * * * 

(ix) Average flow-line rate of gas 

(average of ‘‘SFRp’’ from Equation W–8 

or W–9 of this subpart, as applicable), 

at standard conditions in cubic feet per 

hour. 

(x) Cumulative amount of time that 

wells were left open to the atmosphere 

during unloading events (sum of 

‘‘HRp,q’’ from Equation W–8 or W–9 of 

this subpart, as applicable), in hours. 

(xi) For wells without plunger lifts, 

the information in paragraphs 

(f)(2)(xi)(A) through (C) of this section. 

(A) Average internal casing diameter 

(average of ‘‘CDp’’ from Equation W–8 of 

this subpart), in inches. 

(B) Average well depth (average of 

‘‘WDp’’ from Equation W–8 of this 

subpart), in feet. 

(C) Average shut-in pressure, surface 

pressure, or casing pressure (average of 

‘‘SPp’’ from Equation W–8 of this 

subpart), in pounds per square inch 

absolute. 

(xii) For wells with plunger lifts, the 

information in paragraphs (f)(2)(xii)(A) 

through (C) of this section. 

(A) Average internal tubing diameter 

(average of ‘‘TDp’’ from Equation W–9 of 

this subpart), in inches. 

(B) Average tubing depth (average of 

‘‘WDp’’ from Equation W–9 of this 

subpart), in feet. 

(C) Average flow line pressure 

(average of ‘‘SPp’’ from Equation W–9 of 

this subpart), in pounds per square inch 

absolute. 

(g) * * * 

(10) If the well emissions were routed 

to a flare, then you must report the 

information specified in paragraphs 

(g)(10)(i) through (xi) of this section. 

(i) Indicate whether the total 

emissions reported under paragraphs 

(g)(8) and (9) of this section include 

vented emissions during the initial 

flowback period. 

(ii) Indicate whether the flare was 

monitored with a CEMS in accordance 

with § 98.233(n)(8). If a CEMS was used, 

then paragraph (g)(9) and paragraphs 

(g)(10)(iii) through (xi) of this section do 

not apply. 

(iii) Indicate whether all of the gas 

from completions and workovers was 

measured using continuous flow 

monitors. 

(iv) Indicate whether all of the gas 

streams from completions and 

workovers were measured with 

continuous gas composition analyzers. 

(v) Indicate whether only the default 

HHV, only a site-specific HHV(s), or 

both the default and site-specific HHVs 

(depending on the stream to the flare) 

were used in Equation W–40 to 

calculate N2O emissions. 

(vi) Total volume of gas from 

completions and workovers to all flares, 

in standard cubic feet (‘‘Vs’’ in 

Equations W–19 and W–20 of this 

subpart). 

(vii) Fraction of total flared gas from 

completions and workovers routed to 


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un-lit flares (‘‘Zu’’ in Equation W–19 of 

this subpart). 

(viii) Average flare combustion 

efficiency, expressed as a fraction of gas 

from completions and workovers 

combusted by a burning flare. 

(ix) Flow-weighted average mole 

fraction of CH4 in gas from completions 

and workovers routed to flares (‘‘XCH4’’ 

in Equation W–19 of this subpart). 

(x) Flow-weighted average mole 

fraction of CO2 in gas from completions 

and workovers routed to flares (‘‘XCO2’’ 

in Equation W–20 of this subpart). 

(xi) Total N2O emissions, in metric 

tons N2O. 

(h) * * * 

(2) For each sub-basin with gas well 

completions without hydraulic 

fracturing and with flaring, report the 

information specified in paragraphs 

(h)(2)(i) through (xvi) of this section. 

* * * * * 

(v) Indicate whether the flare was 

monitored with a CEMS in accordance 

with § 98.233(n)(8). If a CEMS was used, 

then paragraphs (h)(2)(vi) through (xii), 

(xiv), and (xv) of this section do not 

apply. 

(vi) Indicate whether all of the gas 

from completions was measured using 

continuous flow monitors. 

(vii) Indicate whether all of the gas 

streams from completions were 

measured with continuous gas 

composition analyzers. 

(viii) Indicate whether only the 

default HHV, only a site-specific 

HHV(s), or both the default and sitespecific HHVs (depending on the stream 

to the flare) were used in Equation W– 

40 to calculate N2O emissions. 

(ix) Total volume of gas from 

completions to all flares, in standard 

cubic feet (‘‘Vs’’ in Equations W–19 and 

W–20 of this subpart). 

(x) Fraction of total flared gas from 

completions routed to un-lit flares (‘‘Zu’’ 

in Equation W–19 of this subpart). 

(xi) Average flare combustion 

efficiency, expressed as a fraction of gas 

from completions combusted by a 

burning flare. 

(xii) Flow-weighted average mole 

fraction of CH4 in gas from completions 

routed to flares (‘‘XCH4’’ in Equation W– 

19 of this subpart). 

(xiii) Flow-weighted average mole 

fraction of CO2 in gas from completions 

routed to flares (‘‘XCO2’’ in Equation W– 

20 of this subpart). 

(xiv) Annual CO2 emissions, in metric 

tons CO2, that resulted from 

completions that flared gas calculated 

according to § 98.233(h)(2). 

(xv) Annual CH4 emissions, in metric 

tons CH4, that resulted from 

completions that flared gas calculated 

according to § 98.233(h)(2). 

(xvi) Annual N2O emissions, in metric 

tons N2O, that resulted from 

completions that flared gas calculated 

according to § 98.233(h)(2). 

* * * * * 

(4) For each sub-basin with gas well 

workovers without hydraulic fracturing 

and with flaring, report the information 

specified in paragraphs (h)(4)(i) through 

(xiv) of this section. 

* * * * * 

(iii) Indicate whether the flare was 

monitored with a CEMS in accordance 

with § 98.233(n)(8). If a CEMS was used, 

then paragraphs (h)(4)(iv) through (x), 

(xii), and (xiii) of this section do not 

apply. 

(iv) Indicate whether all of the gas 

from workovers was measured using 

continuous flow monitors. 

(v) Indicate whether all of the gas 

streams from workovers were measured 

with continuous gas composition 

analyzers. 

(vi) Indicate whether only the default 

HHV, only a site-specific HHV(s), or 

both the default and site-specific HHVs 

(depending on the stream to the flare) 

were used in Equation W–40 to 

calculate N2O emissions. 

(vii) Total volume of gas from 

workovers to all flares, in standard 

cubic feet (‘‘Vs’’ in Equations W–19 and 

W–20 of this subpart). 

(viii) Fraction of total flared gas from 

workovers routed to un-lit flares (‘‘Zu’’ 

in Equation W–19 of this subpart). 

(ix) Average flare combustion 

efficiency, expressed as a fraction of gas 

from workovers combusted by a burning 

flare. 

(x) Flow-weighted average mole 

fraction of CH4 in gas from workovers 

routed to flares (‘‘XCH4’’ in Equation W– 

19 of this subpart). 

(xi) Flow-weighted average mole 

fraction of CO2 in gas from workovers 

routed to flares (‘‘XCO2’’ in Equation W– 

20 of this subpart). 

(xii) Annual CO2 emissions, in metric 

tons CO2 per year, that resulted from 

workovers that flared gas calculated as 

specified in § 98.233(h)(2). 

(xiii) Annual CH4 emissions, in metric 

tons CH4 per year, that resulted from 

workovers that flared gas, calculated as 

specified in § 98.233(h)(2). 

(xiv) Annual N2O emissions, in metric 

tons N2O per year, that resulted from 

workovers that flared gas calculated as 

specified in § 98.233(h)(2). 

(i) * * * 

(1) Report by equipment or event type. 

If you calculated emissions from 

blowdown vent stacks by the seven 

categories listed in § 98.233(i)(2)(iv) for 

onshore natural gas processing, onshore 

natural gas transmission compression, 

LNG import and export equipment, or 

onshore petroleum and natural gas 

gathering and boosting industry 

segments, then you must report the 

equipment or event types and the 

information specified in paragraphs 

(i)(1)(i) through (iii) of this section for 

each equipment or event type. If a 

blowdown event resulted in emissions 

from multiple equipment types, and the 

emissions cannot be apportioned to the 

different equipment types, then you 

may report the information in 

paragraphs (i)(1)(i) through (iii) of this 

section for the equipment type that 

represented the largest portion of the 

emissions for the blowdown event. If 

you calculated emissions from 

blowdown vent stacks by the eight 

categories listed in § 98.233(i)(2)(iv) for 

the onshore natural gas transmission 

pipeline segment, then you must report 

the pipeline segments or event types 

and the information specified in 

paragraphs (i)(1)(i) through (iii) of this 

section for each ‘‘equipment or event 

type’’ (i.e., category). If a blowdown 

event resulted in emissions from 

multiple categories, and the emissions 

cannot be apportioned to the different 

categories, then you may report the 

information in paragraphs (i)(1)(i) 

through (iii) of this section for the 

‘‘equipment or event type’’ (i.e., 

category) that represented the largest 

portion of the emissions for the 

blowdown event. 

* * * * * 

(j) Onshore production and onshore 

petroleum and natural gas gathering 

and boosting storage tanks. You must 

indicate whether your facility sends 

hydrocarbon produced liquids to 

atmospheric tanks. If your facility sends 

hydrocarbon produced liquids to 

atmospheric tanks, then you must 

indicate which Calculation Method(s) 

you used to calculate GHG emissions, 

and you must report the information 

specified in paragraphs (j)(1) and (2) of 

this section as applicable. If you used 

Calculation Method 1 or Calculation 

Method 2 of § 98.233(j), and any 

atmospheric tanks were observed to 

have malfunctioning dump valves 

during the calendar year, then you must 

indicate that dump valves were 

malfunctioning and must report the 

information specified in paragraph (j)(3) 

of this section. 

(1) If you used Calculation Method 1 

or Calculation Method 2 of § 98.233(j) to 

calculate GHG emissions, then you must 

report the information specified in 

paragraphs (j)(1)(i) through (xvi) of this 

section for each sub-basin (for onshore 

production) or county (for onshore 

petroleum and natural gas gathering and 


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boosting) and by calculation method. 

Onshore petroleum and natural gas 

gathering and boosting facilities do not 

report the information specified in 

paragraph (j)(1)(ix) of this section. 

(i) Sub-basin ID (for onshore 

production) or county name (for 

onshore petroleum and natural gas 

gathering and boosting). 

(ii) Calculation method used, and 

name of the software package used if 

using Calculation Method 1. 

(iii) The total annual hydrocarbon 

liquids volume from gas-liquid 

separators and direct from wells or nonseparator equipment that is sent to 

applicable onshore production and 

onshore petroleum and natural gas 

gathering and boosting storage tanks, in 

barrels. You may delay reporting of this 

data element for onshore production if 

you indicate in the annual report that 

wildcat wells and delineation wells are 

the only wells in the sub-basin with 

hydrocarbon liquids production greater 

than or equal to 10 barrels per day and 

flowing to gas-liquid separators or direct 

to storage tanks. If you elect to delay 

reporting of this data element, you must 

report by the date specified in paragraph 

(cc) of this section the total volume of 

hydrocarbon liquids from all wells and 

the well ID number(s) for the well(s) 

included in this volume. 

(iv) The average gas-liquid separator 

or non-separator equipment 

temperature, in degrees Fahrenheit. 

(v) The average gas-liquid separator or 

non-separator equipment pressure, in 

pounds per square inch gauge. 

(vi) The average sales oil or stabilized 

hydrocarbon liquids API gravity, in 

degrees. 

(vii) The flow-weighted average 

concentration (mole fraction) of CO2 in 

flash gas from onshore production and 

onshore natural gas gathering and 

boosting storage tanks (calculated as the 

sum of all products of the concentration 

of CO2 in the flash gas for each storage 

tank times the throughput for that 

storage tank, divided by the sum of all 

throughputs from storage tanks) (‘‘XCO2’’ 

in Equation W–20 of this subpart if the 

flash gas is routed to a flare). 

(viii) The flow-weighted average 

concentration (mole fraction) of CH4 in 

flash gas from onshore production and 

onshore natural gas gathering and 

boosting storage tanks (calculated as the 

sum of all products of the concentration 

of CH4 in the flash gas for each storage 

tank times the throughput for that 

storage tank, divided by the sum of all 

throughputs from storage tanks) (‘‘XCH4’’ 

in Equation W–19 of this subpart and 

‘‘Y1’’ in Equation W–20 of this subpart 

if the flash gas is routed to a flare). 

(ix) The number of wells sending 

hydrocarbon liquids to gas-liquid 

separators or directly to atmospheric 

tanks. 

(x) Count of atmospheric tanks 

specified in paragraphs (j)(1)(x)(A) 

through (D) of this section. 

(A) The number of atmospheric tanks. 

(B) The number of atmospheric tanks 

that vented gas directly to the 

atmosphere and did not control 

emissions using a vapor recovery system 

or one or more flares at any point during 

the reporting year. 

(C) The number of atmospheric tanks 

that routed emissions to vapor recovery 

and/or one or more flares at any point 

during the reporting year. 

(D) The number of atmospheric tanks 

in paragraph (j)(1)(x)(C) of this section 

that had an open or unseated thief hatch 

at some point during the year while the 

tank was also routing emissions to a 

vapor recovery system and/or a flare. 

(xi) For the atmospheric tanks at your 

facility identified in paragraph 

(j)(1)(x)(B) of this section, you must 

report the information specified in 

paragraphs (j)(1)(xi)(A) and (B) of this 

section. 

(A) Annual CO2 emissions, in metric 

tons CO2, that resulted from venting gas 

directly to the atmosphere, calculated 

according to § 98.233(j)(1) and (2). 

(B) Annual CH4 emissions, in metric 

tons CH4, that resulted from venting gas 

directly to the atmosphere, calculated 

according to § 98.233(j)(1) and (2). 

(xii) For the atmospheric tanks at your 

facility identified in paragraph 

(j)(1)(x)(C) of this section, you must 

report the information specified in 

paragraphs (j)(1)(xii)(A) through (N) of 

this section. 

(A) Annual CO2 emissions, in metric 

tons CO2, that resulted from venting gas 

directly to the atmosphere, calculated 

according to § 98.233(j)(1), (2), and (4). 

(B) Annual CH4 emissions, in metric 

tons CH4, that resulted from venting gas 

directly to the atmosphere, calculated 

according to § 98.233(j)(1), (2), and (4). 

(C) Indicate whether the flare was 

monitored with a CEMS in accordance 

with § 98.233(n)(8). If a CEMS was used, 

then paragraphs (j)(1)(xii)(D) through 

(K), (M), and (N) of this section do not 

apply. 

(D) Indicate whether all of the gas 

from the atmospheric tanks in the 

applicable sub-basin or county and 

subject to this paragraph (j)(1)(xii) was 

measured using a continuous flow 

monitor. 

(E) Indicate whether all of the gas 

from the atmospheric tanks in the 

applicable sub-basin or county and 

subject to this paragraph (j)(1)(xii) was 

measured with a continuous gas 

composition analyzer. 

(F) Indicate whether only the default 

HHV, only a site-specific HHV(s), or 

both the default and site-specific HHVs 

(depending on the stream to the flare) 

were used in Equation W–40 to 

calculate N2O emissions. 

(G) Total volume of gas from the 

atmospheric tanks in the applicable subbasin or county and subject to this 

paragraph (j)(1)(xii) that was routed to a 

flare, in standard cubic feet (‘‘Vs’’ in 

Equations W–19 and W–20 of this 

subpart). 

(H) Fraction of total flared gas from 

the atmospheric tanks in the applicable 

sub-basin or county and subject to this 

paragraph (j)(1)(xii) that was routed to 

un-lit flares (‘‘Zu’’ in Equation W–19 of 

this subpart). 

(I) Average flare combustion 

efficiency, expressed as a fraction of gas 

from the atmospheric tanks in the 

applicable sub-basin or county and 

subject to this paragraph (j)(1)(xii) 

combusted by a burning flare. 

(J) Annual CO2 emissions, in metric 

tons CO2, from flares used to control 

emissions, calculated according to 

§ 98.233(j)(5). 

(K) Annual CH4 emissions, in metric 

tons CH4, from flares used to control 

emissions, calculated according to 

§ 98.233(j)(5). 

(L) Annual N2O emissions, in metric 

tons N2O, from flares used to control 

emissions, calculated according to 

§ 98.233(j)(5). 

(M) Total CO2 mass, in metric tons 

CO2, that was recovered during the 

calendar year using a vapor recovery 

system. 

(N) Total CH4 mass, in metric tons 

CH4, that was recovered during the 

calendar year using a vapor recovery 

system. 

(xiii) For the atmospheric tanks at 

your facility identified in paragraph 

(j)(1)(x)(D) of this section, the total 

volume of gas vented through open or 

unseated thief hatches, in scf, during 

periods while the tanks were also 

routing emissions to vapor recovery 

systems and/or flares. 

(2) If you used Calculation Method 3 

to calculate GHG emissions, then you 

must report the information specified in 

paragraphs (j)(2)(i) through (iii) of this 

section. 

(i) Report the information specified in 

paragraphs (j)(2)(i)(A) through (E) of this 

section, at the basin level, for 

atmospheric tanks where emissions 

were calculated using Calculation 

Method 3 of § 98.233(j). 

(A) The total annual hydrocarbon 

liquids throughput that is sent to all 

atmospheric tanks in the basin, in 


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barrels. You may delay reporting of this 

data element for onshore production if 

you indicate in the annual report that 

wildcat wells and delineation wells are 

the only wells in the sub-basin with 

hydrocarbon liquids production less 

than 10 barrels per day and that send 

hydrocarbon liquids to atmospheric 

tanks. If you elect to delay reporting of 

this data element, you must report by 

the date specified in § 98.236(cc) the 

total annual hydrocarbon liquids 

throughput from all wells and the well 

ID number(s) for the well(s) included in 

this volume. 

(B) An estimate of the fraction of 

hydrocarbon liquids throughput 

reported in paragraph (j)(2)(i)(A) of this 

section sent to atmospheric tanks in the 

basin that controlled emissions with 

flares. 

(C) An estimate of the fraction of 

hydrocarbon liquids throughput 

reported in paragraph (j)(2)(i)(A) of this 

section sent to atmospheric tanks in the 

basin that controlled emissions with 

vapor recovery systems. 

(D) The number of atmospheric tanks 

in the basin. 

(E) The total number of separators, 

wells, or non-separator equipment 

(‘‘Count’’ from Equation W–15 of this 

subpart) in the basin. 

(ii) Report the information specified 

in paragraphs (j)(2)(ii)(A) through (D) of 

this section for each sub-basin (for 

onshore production) or county (for 

onshore petroleum and natural gas 

gathering and boosting) with 

atmospheric tanks whose emissions 

were calculated using Calculation 

Method 3 of § 98.233(j) and that either 

did not control emissions with flares or 

that used flares to control emissions 

from less than half the annual 

hydrocarbon liquids received. 

(A) Sub-basin ID (for onshore 

production) or county name (for 

onshore petroleum and natural gas 

gathering and boosting). 

(B) The number of atmospheric tanks 

in the sub-basin (for onshore 

production) or county (for onshore 

petroleum and natural gas gathering and 

boosting) that did not control emissions 

with flares and for which emissions 

were calculated using Calculation 

Method 3. 

(C) Annual CO2 emissions, in metric 

tons CO2, from atmospheric tanks in the 

sub-basin (for onshore production) or 

county (for onshore petroleum and 

natural gas gathering and boosting) that 

did not control emissions with flares, 

calculated using Equation W–15 of 

§ 98.233(j) and adjusted using the 

requirements described in § 98.233(j)(4), 

if applicable. 

(D) Annual CH4 emissions, in metric 

tons CH4, from atmospheric tanks in the 

sub-basin (for onshore production) or 

county (for onshore petroleum and 

natural gas gathering and boosting) that 

did not control emissions with flares, 

calculated using Equation W–15 of 

§ 98.233(j) and adjusted using the 

requirements described in § 98.233(j)(4), 

if applicable. 

(iii) Report the information specified 

in paragraphs (j)(2)(iii)(A) through (N) of 

this section for each sub-basin (for 

onshore production) or county (for 

onshore petroleum and natural gas 

gathering and boosting) with 

atmospheric tanks whose emissions 

were calculated using Calculation 

Method 3 of § 98.233(j) and that used 

flares to control emissions from at least 

half the annual hydrocarbon liquids 

received. 

(A) Sub-basin ID (for onshore 

production) or county name (for 

onshore petroleum and natural gas 

gathering and boosting). 

(B) The number of atmospheric tanks 

in the sub-basin (for onshore 

production) or county (for onshore 

petroleum and natural gas gathering and 

boosting) that controlled emissions with 

flares and for which emissions were 

calculated using Calculation Method 3. 

(C) Indicate whether the flare was 

monitored with a CEMS in accordance 

with § 98.233(n)(8). If a CEMS was used, 

then paragraphs (j)(2)(iii)(D) through 

(K), (M), and (N) of this section do not 

apply. 

(D) Indicate whether all of the gas 

from the atmospheric tanks in the 

applicable sub-basin or county and 

subject to this paragraph (j)(2)(iii) was 

measured using a continuous flow 

monitor. 

(E) Indicate whether all of the gas 

from the atmospheric tanks in the 

applicable sub-basin or county and 

subject to this paragraph (j)(2)(iii) was 

measured with a continuous gas 

composition analyzer. 

(F) Indicate whether only the default 

HHV, only a site-specific HHV(s), or 

both the default and site-specific HHVs 

(depending on the stream to the flare) 

were used in Equation W–40 to 

calculate N2O emissions. 

(G) Total volume of gas from the 

atmospheric tanks in the applicable subbasin or county and subject to this 

paragraph (j)(2)(iii) that was routed to a 

flare, in standard cubic feet (‘‘Vs’’ in 

Equations W–19 and W–20 of this 

subpart). 

(H) Fraction of total flared gas from 

the atmospheric tanks in the applicable 

sub-basin or county and subject to this 

paragraph (j)(2)(iii) that was routed to 

un-lit flares (‘‘Zu’’ in Equation W–19 of 

this subpart). 

(I) Average flare combustion 

efficiency, expressed as a fraction of gas 

from the atmospheric tanks in the 

applicable sub-basin or county and 

subject to this paragraph (j)(2)(iii) 

combusted by a burning flare. 

(J) Flow-weighted average mole 

fraction of CH4 in gas from the 

atmospheric tanks in the applicable subbasin or county and subject to this 

paragraph (j)(2)(iii) and routed to a flare 

(‘‘XCH4’’ in Equation W–19 of this 

subpart). 

(K) Flow-weighted average mole 

fraction of CO2 in gas from the 

atmospheric tanks in the applicable subbasin or county and subject to this 

paragraph (j)(2)(iii) and routed to a flare 

(‘‘XCO2’’ in Equation W–20 of this 

subpart). 

(L) Annual CO2 emissions, in metric 

tons CO2, from atmospheric tanks that 

controlled emissions with flares, 

calculated according to § 98.233(j)(5) 

and adjusted using the requirements 

described in § 98.233(j)(4), if applicable. 

(M) Annual CH4 emissions, in metric 

tons CH4, from atmospheric tanks that 

controlled emissions with flares, 

calculated according to § 98.233(j)(5) 

and adjusted using the requirements 

described in § 98.233(j)(4), if applicable. 

(N) Annual N2O emissions, in metric 

tons N2O, from atmospheric tanks that 

controlled emissions with flares, 

calculated according to § 98.233(j)(5). 

(3) * * * 

(ii) The total time the dump valves on 

gas-liquid separators did not close 

properly in the calendar year, in hours 

(sum of the ‘‘Tdv’’ values used in 

Equation W–16 of this subpart). 

* * * * * 

(k) * * * 

(1) * * * 

(ii) Indicate if there is a flare attached 

to the transmission storage tank vent 

stack. 

(iii) Method used to determine if 

dump valve leakage occurred. 

(iv) Indicate whether scrubber dump 

valve leakage occurred for the 

transmission storage tank vent 

according to § 98.233(k)(2) or 

§ 98.233(k)(5). 

(2) If scrubber dump valve leakage 

occurred for a transmission storage tank 

vent stack, as reported in paragraph 

(k)(1)(iv) of this section, and the vent 

stack vented directly to the atmosphere 

during the calendar year, then you must 

report the information specified in 

paragraphs (k)(2)(i) through (v) of this 

section for each transmission storage 

vent stack where scrubber dump valve 

leakage occurred. 

* * * * * 


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(3) If scrubber dump valve leakage 

occurred for a transmission storage tank 

vent stack, as reported in paragraph 

(k)(1)(iv) of this section, and the vent 

stack routed to a flare during the 

calendar year, then you must report the 

information specified in paragraphs 

(k)(3)(i) through (iii) of this section. 

(i) Indicate whether leak rate was 

determined using a continuous flow 

measurement device for the duration of 

the time that flaring occurred or if an 

annual measurement was conducted in 

accordance with paragraph (k)(1)(ii) of 

this section. 

(ii) Measured leakage rate (average 

leak rate from a continuous flow 

measurement device) in standard cubic 

feet per hour. 

(iii) Duration of time that flaring 

occurred in hours, as defined in 

§ 98.233(k)(3) (may use best available 

data if a continuous flow measurement 

device was used). 

(l) * * * 

(1) If you used Equation W–17A of 

§ 98.233 to calculate annual volumetric 

natural gas emissions at actual 

conditions from oil wells and the 

emissions are not routed to a flare, then 

you must report the information 

specified in paragraphs (l)(1)(i) through 

(vii) of this section. 

* * * * * 

(2) If you used Equation W–17A of 

§ 98.233 to calculate annual volumetric 

natural gas emissions at actual 

conditions from oil wells and the 

emissions are routed to a flare, then you 

must report the information specified in 

paragraphs (l)(2)(i) through (xvii) of this 

section. All reported data elements 

should be specific to the wells for which 

Equation W–17A of § 98.233 was used 

and for which well testing emissions 

were routed to flares. 

* * * * * 

(vi) Indicate whether the flare was 

monitored with a CEMS in accordance 

with § 98.233(n)(8). If a CEMS was used, 

then paragraphs (l)(2)(vii) through (xiv), 

(xvi), and (xvii) of this section do not 

apply. 

(vii) Indicate whether all of the gas 

from well testing routed to flares was 

measured using continuous flow 

monitors. 

(viii) Indicate whether all of the gas 

streams from well testing routed to 

flares were measured with continuous 

gas composition analyzers. 

(ix) Indicate whether only the default 

HHV, only a site-specific HHV(s), or 

both the default and site-specific HHVs 

(depending on the stream to the flare) 

were used in Equation W–40 to 

calculate N2O emissions. 

(x) Total volume of gas from well 

testing routed to all flares, in standard 

cubic feet (‘‘Vs’’ in Equations W–19 and 

W–20 of this subpart). 

(xi) Fraction of total flared gas from 

well testing routed to un-lit flares (‘‘Zu’’ 

in Equation W–19 of this subpart). 

(xii) Average flare combustion 

efficiency, expressed as a fraction of gas 

from well testing combusted by a 

burning flare. 

(xiii) Flow-weighted average mole 

fraction of CH4 in gas from well testing 

routed to flares (‘‘XCH4’’ in Equation W– 

19 of this subpart). 

(xiv) Flow-weighted average mole 

fraction of CO2 in gas from well testing 

routed to flares (‘‘XCO2’’ in Equation W– 

20 of this subpart). 

(xv) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(l). 

(xvi) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(l). 

(xvii) Annual N2O emissions, in 

metric tons N2O, calculated according 

to § 98.233(l). 

(3) If you used Equation W–17B of 

§ 98.233 to calculate annual volumetric 

natural gas emissions at actual 

conditions from gas wells and the 

emissions were not routed to a flare, 

then you must report the information 

specified in paragraphs (l)(3)(i) through 

(vi) of this section. 

* * * * * 

(4) If you used Equation W–17B of 

§ 98.233 to calculate annual volumetric 

natural gas emissions at actual 

conditions from gas wells and the 

emissions were routed to a flare, then 

you must report the information 

specified in paragraphs (l)(4)(i) through 

(xvi) of this section. All reported data 

elements should be specific to the wells 

for which Equation W–17B of § 98.233 

was used and for which well testing 

emissions were routed to flares. 

* * * * * 

(v) Indicate whether the flare was 

monitored with a CEMS in accordance 

with § 98.233(n)(8). If a CEMS was used, 

then paragraphs (l)(4)(vi) through (xiii), 

(xv), and (xvi) of this section do not 

apply. 

(vi) Indicate whether all of the gas 

from well testing routed to flares was 

measured using continuous flow 

monitors. 

(vii) Indicate whether all of the gas 

streams from well testing routed to 

flares were measured with continuous 

gas composition analyzers. 

(viii) Indicate whether only the 

default HHV, only a site-specific 

HHV(s), or both the default and sitespecific HHVs (depending on the stream 

to the flare) were used in Equation W– 

40 to calculate N2O emissions. 

(ix) Total volume of gas from well 

testing routed to all flares, in standard 

cubic feet (‘‘Vs’’ in Equations W–19 and 

W–20 of this subpart). 

(x) Fraction of total flared gas from 

well testing routed to un-lit flares (‘‘Zu’’ 

in Equation W–19 of this subpart). 

(xi) Average flare combustion 

efficiency, expressed as a fraction of gas 

from well testing combusted by a 

burning flare. 

(xii) Flow-weighted average mole 

fraction of CH4 in gas from well testing 

routed to flares (‘‘XCH4’’ in Equation W– 

19 of this subpart). 

(xiii) Flow-weighted average mole 

fraction of CO2 in gas from well testing 

routed to flares (‘‘XCO2’’ in Equation W– 

20 of this subpart). 

(xiv) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(l). 

(xv) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(l). 

(xvi) Annual N2O emissions, in metric 

tons N2O, calculated according to 

§ 98.233(l). 

(m) * * * 

(4) Average gas to oil ratio, in 

standard cubic feet of gas per barrel of 

oil (average of the ‘‘GOR’’ values used 

in Equation W–18 of this subpart). Do 

not report the GOR if you vented or 

flared associated gas and used a 

continuous flow monitor to determine 

the total volume of associated gas 

vented or routed to the flare in the subbasin (i.e., if you did not use Equation 

W–18 for any wells with associated gas 

venting or flaring emissions in the subbasin). 

(5) Volume of oil produced, in barrels, 

in the calendar year only during the 

time periods in which associated gas 

was vented or flared (the sum of ‘‘Vp,q’’ 

used in Equation W–18 of § 98.233). 

You may delay reporting of this data 

element if you indicate in the annual 

report that wildcat wells and/or 

delineation wells are the only wells 

from which associated gas was vented 

or flared. If you elect to delay reporting 

of this data element, you must report by 

the date specified in § 98.236(cc) the 

volume of oil produced for well(s) with 

associated gas venting and flaring and 

the well ID number(s) for the well(s) 

included in the measurement. Do not 

report the volume of oil produced if you 

vented or flared associated gas and used 

a continuous flow monitor to determine 

the total volume of associated gas 

vented or routed to the flare in the subbasin (i.e., if you did not use Equation 

W–18 for any wells with associated gas 

venting or flaring emissions in the subbasin). 


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(6) Total volume of associated gas sent 

to sales, in standard cubic feet, in the 

calendar year only during time periods 

in which associated gas was vented or 

flared (the sum of ‘‘SG’’ values used in 

Equation W–18 of § 98.233(m)). You 

may delay reporting of this data element 

if you indicate in the annual report that 

wildcat wells and/or delineation wells 

are the only wells from which 

associated gas was vented or flared. If 

you elect to delay reporting of this data 

element, you must report by the date 

specified in paragraph (cc) of this 

section the measured total volume of 

associated gas sent to sales for well(s) 

with associated gas venting and flaring 

and the well ID number(s) for the well(s) 

included in the measurement. Do not 

report the volume of gas sent to sales if 

you vented or flared associated gas and 

used a continuous flow monitor to 

determine the total volume of associated 

gas vented or routed to the flare in the 

sub-basin (i.e., if you did not use 

Equation W–18 for any wells with 

associated gas venting or flaring 

emissions in the sub-basin). 

(7) If you had associated gas 

emissions vented directly to the 

atmosphere without flaring, then you 

must report the information specified in 

paragraphs (m)(7)(i) through (viii) of this 

section for each sub-basin. 

(i) Total number of wells for which 

associated gas was vented directly to the 

atmosphere without flaring and a list of 

their well ID numbers. 

(ii) Indicate whether all of the 

associated gas volume vented in the 

sub-basin was measured using 

continuous flow monitors. 

(iii) Indicate whether all associated 

gas streams vented in the sub-basin 

were measured with continuous gas 

composition analyzers. 

(iv) Total volume of associated gas 

vented in the sub-basin, in standard 

cubic feet. 

(v) Flow-weighted average mole 

fraction of CH4 in associated gas vented 

in the sub-basin. 

(vi) Flow-weighted average mole 

fraction of CO2 in associated gas vented 

in the sub-basin. 

(vii) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(m)(3) and (4). 

(viii) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(m)(3) and (4). 

(8) If you had associated gas 

emissions that were flared, then you 

must report the information specified in 

paragraphs (m)(8)(i) through (xiii) of this 

section for each sub-basin. 

(i) Total number of wells for which 

associated gas was flared and a list of 

their well ID numbers. 

(ii) Indicate whether the flare was 

monitored with a CEMS in accordance 

with § 98.233(n)(8). If a CEMS was used, 

then paragraphs (m)(8)(iii) through (x), 

(xii), and (xiii) of this section do not 

apply. 

(iii) Indicate whether all of the 

associated gas volume routed to flares in 

the sub-basin was measured using 

continuous flow monitors. 

(iv) Indicate whether all associated 

gas streams routed to flares in the subbasin were measured with continuous 

gas composition analyzers. 

(v) Indicate whether only the default 

HHV, only a site-specific HHV(s), or 

both the default and site-specific HHVs 

(depending on the stream to the flare) 

were used in Equation W–40 to 

calculate N2O emissions. 

(vi) Total volume of associated gas 

routed to all flares in the sub-basin, in 

standard cubic feet (‘‘Vs’’ in Equations 

W–19 and W–20 of this subpart). 

(vii) Fraction of total flared associated 

gas in the sub-basin routed to un-lit 

flares (‘‘Zu’’ in Equation W–19 of this 

subpart). 

(viii) Average flare combustion 

efficiency, expressed as a fraction of 

associated gas combusted by a burning 

flare. 

(ix) Flow-weighted average mole 

fraction of CH4 in associated gas routed 

to flares in the sub-basin (‘‘XCH4’’ in 

Equation W–19 of this subpart). 

(x) Flow-weighted average mole 

fraction of CO2 in associated gas routed 

to flares in the sub-basin (‘‘XCO2’’ in 

Equation W–20 of this subpart). 

(xi) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(m)(5). 

(xii) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(m)(5). 

(xiii) Annual N2O emissions, in 

metric tons N2O, calculated according to 

§ 98.233(m)(5). 

(n) Flare stacks. You must indicate if 

your facility has any flare stacks to 

which emissions are routed from 

miscellaneous flared sources (i.e., 

sources other than those subject to 

§ 98.233(e), (g), (h), (j), (l), or (m), as 

applicable for the industry segment). If 

you have any miscellaneous flared 

sources, you must report the 

information specified in paragraph 

(n)(1) of this section for each flare used 

to control emissions from such sources. 

Additionally, for each flare at your 

facility, regardless of the source(s) 

controlled, you must report the 

information specified in paragraph 

(n)(2) of this section. 

(1) For each flare stack used to control 

miscellaneous flared sources, you must 

report the information specified in 

paragraph (n)(1)(i) through (xiv) of this 

section. 

(i) Unique name or ID for the flare 

stack. For the onshore petroleum and 

natural gas production and onshore 

petroleum and natural gas gathering and 

boosting industry segments, a different 

name or ID may be used for a single 

flare stack for each location where it 

operates at in a given calendar year. 

(ii) Indicate whether the flare stack 

has a continuous flow measurement 

device. 

(iii) Indicate whether the flare stack 

has a continuous gas composition 

analyzer on feed gas to the flare. 

(iv) Indicate whether only the default 

HHV, only a site-specific HHV(s), or 

both the default and site-specific HHVs 

(depending on the stream to the flare) 

were used in Equation W–40 to 

calculate N2O emissions. 

(v) Estimated fraction of total volume 

flared that was received from another 

facility solely for flaring (e.g., gas 

separated from liquid at a production 

facility that is routed to a flare that is 

assigned to an onshore petroleum and 

natural gas gathering and boosting 

facility). 

(vi) Volume of gas from miscellaneous 

flared sources sent to the flare, in 

standard cubic feet (‘‘Vs’’ in Equations 

W–19 and W–20 of this subpart). 

(vii) Fraction of the feed gas sent to an 

un-lit flare (‘‘Zu’’ in Equation W–19 of 

this subpart). 

(viii) Flare combustion efficiency, 

expressed as the fraction of gas 

combusted by a burning flare. 

(ix) Flow-weighted average mole 

fraction of CH4 in the feed gas from 

miscellaneous flared sources to the flare 

(‘‘XCH4’’ in Equation W–19 of this 

subpart). 

(x) Flow-weighted average mole 

fraction of CO2 in the feed gas from 

miscellaneous flared sources to the flare 

(‘‘XCO2’’ in Equation W–20 of this 

subpart). 

(xi) Annual CO2 emissions, in metric 

tons CO2 (refer to Equation W–20 of this 

subpart). If gas from an acid gas removal 

unit is routed to the flare, then the CO2

emissions to report should exclude the 

CO2 emissions reported under 

paragraph (d)(1)(v) of this section to 

prevent double counting of emissions. 

(xii) Annual CH4 emissions, in metric 

tons CH4 (refer to Equation W–19 of this 

subpart). 

(xiii) Annual N2O emissions, in 

metric tons N2O (refer to Equation W– 

40 of this subpart). 

(xiv) Indicate whether a CEMS was 

used to measure emissions from the 

flare. If a CEMS was used to measure 

emissions from the flare, then the 

information specified in paragraphs 


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(n)(1)(ii) through (x), (xii), and (xiii) of 

this section do not apply for that flare; 

report only the CO2 emissions as 

specified in paragraph (n)(1)(xi) of this 

section. 

(2) For each flare stack at your facility, 

you must report the information 

specified in paragraphs (n)(2)(i) through 

(ix) of this section. 

(i) Unique name or ID for the flare 

stack. 

(ii) Indicate each emission source type 

that routed emissions to the flare stack 

during the reporting year (i.e., 

dehydrator vents, well venting during 

completions and workovers with 

hydraulic fracturing, gas well venting 

during completions and workovers 

without hydraulic fracturing, onshore 

production and onshore petroleum and 

natural gas gathering and boosting 

storage tanks, well testing venting and 

flaring, associated gas venting and 

flaring, miscellaneous flared sources). 

(iii) Total volume of gas routed to the 

flare. 

(iv) Indicate the type of flare (i.e., 

open ground-level flare, enclosed 

ground-level flare, open elevated flare, 

or enclosed elevated flare). 

(v) Indicate the type of flare assist 

(i.e., unassisted, air-assisted with single 

speed fan/blower, air-assisted with dual 

speed fan/blower, air-assisted with 

variable speed fan/blower, steamassisted, or pressure-assisted). 

(vi) Indicate whether the flare has a 

continuous pilot or autoigniter. 

(vii) If the flare has a continuous pilot, 

indicate whether the presence of flame 

is continuously monitored. 

(viii) If the flare has a continuous 

pilot and the presence of a flame is not 

continuously monitored, indicate how 

periods when the pilot is not lit are 

identified (i.e., assumed pilot is always 

lit, assumed pilot was unlit for a fixed 

number of hours or fraction of operating 

hours, visual observations of flare flame, 

other (specify)). 

(ix) Estimated fraction of the total 

volume routed to the flare when it was 

not lit. 

(o) * * * 

(1) Compressor activity data. Report 

the information specified in paragraphs 

(o)(1)(i) through (x) of this section, as 

applicable, for each centrifugal 

compressor located at your facility. 

(i) Unique name or ID for the 

centrifugal compressor. 

(ii) Hours in operating-mode. 

(iii) Hours in standby-pressurizedmode. 

(iv) Hours in not-operatingdepressurized-mode. 

(v) If you conducted volumetric 

emission measurements as specified in 

§ 98.233(o)(1): 

(A) Indicate whether the compressor 

was measured in operating-mode. 

(B) Indicate whether the compressor 

was measured in standby-pressurizedmode. 

(C) Indicate whether the compressor 

was measured in not-operatingdepressurized-mode. 

(vi) Indicate whether the compressor 

has blind flanges installed and 

associated dates. 

(vii) Indicate whether the compressor 

has wet or dry seals. 

(viii) If the compressor has wet seals, 

the number of wet seals. 

(ix) If the compressor has dry seals, 

the number of dry seals. 

(x) Power output of the compressor 

driver (hp). 

(2) * * * 

(i) * * * 

(B) Centrifugal compressor source 

(wet seal, dry seal, isolation valve, or 

blowdown valve). 

* * * * * 

(ii) * * * 

(A) Indicate whether the leak or vent 

is for a single compressor source or 

manifolded group of compressor sources 

and whether the emissions from the leak 

or vent are released to the atmosphere, 

routed to a flare, combustion, or vapor 

recovery. 

* * * * * 

(5) * * * 

(i) Report the following activity data. 

(A) Total number of centrifugal 

compressors at the facility. 

(B) Number of centrifugal 

compressors that have wet seals. 

(C) Number of centrifugal 

compressors that have atmospheric wet 

seal oil degassing vents (i.e., wet seal oil 

degassing vents where the emissions are 

released to the atmosphere rather than 

being routed to flares, combustion, or 

vapor recovery). 

(ii) Annual CO2 emissions, in metric 

tons CO2, from centrifugal compressors 

with atmospheric wet seal oil degassing 

vents. 

(iii) Annual CH4 emissions, in metric 

tons CH4, from centrifugal compressors 

with atmospheric wet seal oil degassing 

vents. 

(p) * * * 

(1) Compressor activity data. Report 

the information specified in paragraphs 

(p)(1)(i) through (vii) of this section, as 

applicable, for each reciprocating 

compressor located at your facility. 

(i) Unique name or ID for the 

reciprocating compressor. 

(ii) Hours in operating-mode. 

(iii) Hours in standby-pressurizedmode. 

(iv) Hours in not-operatingdepressurized-mode. 

(v) If you conducted volumetric 

emission measurements as specified in 

§ 98.233(p)(1): 

(A) Indicate whether the compressor 

was measured in operating-mode. 

(B) Indicate whether the compressor 

was measured in standby-pressurizedmode. 

(C) Indicate whether the compressor 

was measured in not-operatingdepressurized-mode. 

(vi) Indicate whether the compressor 

has blind flanges installed and 

associated dates. 

(vii) Power output of the compressor 

driver (hp). 

(2) * * * 

(ii) * * * 

(A) Indicate whether the leak or vent 

is for a single compressor source or 

manifolded group of compressor sources 

and whether the emissions from the leak 

or vent are released to the atmosphere, 

routed to a flare, combustion, or vapor 

recovery. 

* * * * * 

(3) * * * 

(ii) For each compressor mode-source 

combination where a reporter emission 

factor as calculated in Equation W–28 

was used to calculate emissions in 

Equation W–27, report the information 

specified in paragraphs (p)(3)(ii)(A) 

through (D) of this section. 

* * * * * 

(5) * * * 

(i) Report the following activity data. 

(A) Total number of reciprocating 

compressors at the facility. 

(B) Number of reciprocating 

compressors that have rod packing 

emissions vented to the atmosphere 

(i.e., rod packing vents where the 

emissions are released to the 

atmosphere rather than being routed to 

flares, combustion, or vapor recovery). 

(ii) Annual CO2 emissions, in metric 

tons CO2, from reciprocating 

compressors with rod packing emissions 

vented to the atmosphere. 

(iii) Annual CH4 emissions, in metric 

tons CH4, from reciprocating 

compressors with rod packing emissions 

vented to the atmosphere. 

(q) * * * 

(1) You must report the information 

specified in paragraphs (q)(1)(i) through 

(vii) of this section. 

* * * * * 

(iii) Except for natural gas distribution 

facilities, indicate whether any of the 

leak detection surveys used in 

calculating emissions per § 98.233(q)(2) 

were conducted for compliance with 

any of the standards in paragraphs 

(q)(1)(iii)(A) through (E) of this section. 

Report the indication per facility, not 

per component type, and indicate all 

that apply for the facility. 


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(A) The well site or compressor 

station fugitive emissions standards in 

§ 60.5397a of this chapter. 

(B) The well site or compressor 

station fugitive emissions standards in 

part 60, subpart OOOOb of this chapter. 

(C) The well site or compressor 

station fugitive emissions standards in 

an applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter. 

(D) The standards for equipment leaks 

at onshore natural gas plants in part 60, 

subpart OOOOb of this chapter. 

(E) The standards for equipment leaks 

at onshore natural gas plants in an 

applicable approved state plan or 

applicable Federal plan in part 62 of 

this chapter. 

* * * * * 

(vi) Report whether emissions were 

calculated using Calculation Method 1 

(leaker factor emission calculation 

methodology) and/or using Calculation 

Method 2 (leaker measurement 

methodology). 

(vii) For facilities in onshore 

petroleum and natural gas production 

and onshore petroleum and natural gas 

gathering and boosting, report the 

number of major equipment (as listed in 

Table W–1A) by service type for which 

leak detection surveys were conducted 

and emissions calculated according to 

§ 98.233(q). 

(2) You must indicate whether your 

facility contains any of the component 

types subject to or complying with 

§ 98.233(q) that are listed in 

§ 98.232(c)(21), (d)(7), (e)(7) or (8), (f)(5), 

through (8), (g)(4), (g)(6) or (7), (h)(5), 

(h)(7) or (8), (i)(1), or (j)(10) for your 

facility’s industry segment. For each 

component type that is located at your 

facility, you must report the information 

specified in paragraphs (q)(2)(i) through 

(v) of this section. If a component type 

is located at your facility and no leaks 

were identified from that component, 

then you must report the information in 

paragraphs (q)(2)(i) through (v) of this 

section but report a zero (‘‘0’’) for the 

information required according to 

paragraphs (q)(2)(ii) through (v) of this 

section. If you used Calculation Method 

1 (leaker factor emission calculation 

methodology) for some complete leak 

surveys and used Calculation Method 2 

(leaker measurement methodology) for 

some complete leak surveys, you must 

report the information specified in 

paragraphs (q)(2)(i) through (v) of this 

section separately for component 

surveys using Calculation Method 1 and 

Calculation Method 2. 

(i) Component type. 

(ii) Total number of the surveyed 

component type that were identified as 

leaking in the calendar year (‘‘xp’’ in 

Equation W–30 of this subpart for the 

component type or the number of leaks 

measured for the specified component 

type according to the provisions in 

§ 98.233(q)(3)(i)). 

(iii) Average time the surveyed 

components are assumed to be leaking 

and operational, in hours (average of 

‘‘Tp,z’’ from Equation W–30 of this 

subpart for the component type or 

average duration of leaks for the 

specified component type determined 

according to the provisions in 

§ 98.233(q)(3)(ii)). 

(iv) Annual CO2 emissions, in metric 

tons CO2, for the component type as 

calculated using Equation W–30 or 

§ 98.233(q)(3)(vi) (for surveyed 

components only). 

(v) Annual CH4 emissions, in metric 

tons CH4, for the component type as 

calculated using Equation W–30 or 

§ 98.233(q)(3)(vi) (for surveyed 

components only). 

* * * * * 

(r) * * * 

(1) You must indicate whether your 

facility contains any of the emission 

source types required to use Equation 

W–32A of § 98.233. You must report the 

information specified in paragraphs 

(r)(1)(i) through (v) of this section 

separately for each emission source type 

required to use Equation W–32A that is 

located at your facility. Onshore 

petroleum and natural gas production 

facilities and onshore petroleum and 

natural gas gathering and boosting 

facilities must report the information 

specified in paragraphs (r)(1)(i) through 

(v) separately by equipment type and 

service type. 

(i) Emission source type. Onshore 

petroleum and natural gas production 

facilities and onshore petroleum and 

natural gas gathering and boosting 

facilities must report the equipment 

type and service type. 

* * * * * 

(s) Offshore petroleum and natural 

gas production. You must report the 

information specified in paragraphs 

(s)(1) through (3) of this section for each 

emission source type listed in the most 

recent BOEM study. 

* * * * * 

(y) Other large release events. You 

must indicate whether there were any 

other large release events from your 

facility during the reporting year. If 

there were any other large release 

events, you must report the total 

number of other large release events 

from your facility that occurred during 

the reporting year and, for each other 

large release event, report the 

information specified in paragraphs 

(y)(1) through (8) of this section. 

(1) Unique release event identification 

number (e.g., Event 1, Event 2). 

(2) The approximate start date, start 

time, and duration (in hours) of the 

release event. 

(3) A general description of the event. 

Include: 

(i) Identification of the equipment 

involved in the release. 

(ii) A description of how the release 

occurred, from one of the following 

categories: fire/explosion, gas well 

blowout, oil well blowout, gas well 

release, oil well release, pressure relief, 

large leak, and other (specify). 

(iii) A description of the technology or 

method used to identify the release. 

(iv) An indication of whether the 

release was identified under the 

provisions of part 60, subpart OOOOb of 

this chapter or an applicable approved 

state plan or applicable Federal plan in 

part 62 of this chapter. 

(v) An indication of whether a portion 

of the natural gas released was 

combusted during the release, and if so, 

the fraction of the natural gas released 

that was estimated to be combusted. 

(4) The total volume of gas released 

during the event in standard cubic feet. 

(5) The volume fraction of CO2 in the 

gas released during the event. 

(6) The volume fraction of CH4 in the 

gas released during the event. 

(7) Annual CO2 emissions, in metric 

tons CO2, from the release event. 

(8) Annual CH4 emissions, in metric 

tons CH4, from the release event. 

(z) Combustion equipment at onshore 

petroleum and natural gas production 

facilities, onshore petroleum and 

natural gas gathering and boosting 

facilities, and natural gas distribution 

facilities. If your facility is required by 

§ 98.232(c)(22), (i)(7), or (j)(12) to report 

emissions from combustion equipment, 

then you must indicate whether your 

facility has any combustion units 

subject to reporting according to 

paragraph (a)(1)(xix), (a)(8)(i), or 

(a)(9)(xiii) of this section. If your facility 

contains any combustion units subject 

to reporting according to paragraph 

(a)(1)(xix), (a)(8)(i), or (a)(9)(xiii) of this 

section, then you must report the 

information specified in paragraphs 

(z)(1) and (2) of this section, as 

applicable. 

* * * * * 

(2) * * * 

(i) The type of combustion unit. For 

internal fuel combustion units of any 

heat capacity that are compressordrivers, you must also specify the 

design class as: 2-stroke lean-burn, 4- 


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stroke lean-burn, 4-stroke rich-burn, or 

other. 

* * * * * 

(iv) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(z)(1) through (3). 

(v) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(z)(1) through (3). 

(vi) Annual N2O emissions, in metric 

tons N2O, calculated according to 

§ 98.233(z)(1) through (3). 

(aa) * * * 

(3) For natural gas processing, if your 

facility fractionates NGLs and also 

reports as a supplier to subpart NN of 

this part, you must report the 

information specified in paragraphs 

(aa)(3)(ii) and (aa)(3)(v) through (viii) of 

this section. Otherwise, report the 

information specified in paragraphs 

(aa)(3)(i) through (viii) of this section. 

(i) The quantity of natural gas 

received at the gas processing plant for 

processing in the calendar year, in 

thousand standard cubic feet. 

* * * * * 

(viii) Indicate whether the facility 

reports as a supplier to subpart NN of 

this part. 

* * * * * 

(10) For onshore petroleum and 

natural gas gathering and boosting 

facilities, report the quantities specified 

in paragraphs (aa)(10)(i) through (vi) of 

this section. 

* * * * * 

(v) The number of compressor stations 

in the facility. 

(vi) The number of centralized oil 

production sites in the facility. 

(11) * * * 

(ii) The quantity of natural gas 

withdrawn from underground natural 

gas storage and LNG storage 

(regasification) facilities owned and 

operated by the onshore natural gas 

transmission pipeline owner or operator 

that are not subject to this subpart in the 

calendar year, in thousand standard 

cubic feet. 

(iii) The quantity of natural gas added 

to underground natural gas storage and 

LNG storage (liquefied) facilities owned 

and operated by the onshore natural gas 

transmission pipeline owner or operator 

that are not subject to this subpart in the 

calendar year, in thousand standard 

cubic feet. 

* * * * * 

(bb) For any missing data procedures 

used, report the information in 

§ 98.3(c)(8) and the procedures used to 

substitute an unavailable value of a 

parameter, except as provided in 

paragraphs (bb)(1) and (2) of this 

section. 

* * * * * 

(cc) If you elect to delay reporting the 

information in paragraph (g)(5)(i) or (ii), 

(g)(5)(iii)(A) or (B), (h)(1)(iv), (h)(2)(iv), 

(j)(1)(iii), (j)(2)(i)(A), (l)(1)(v), (l)(2)(v), 

(l)(3)(iv), (l)(4)(iv), or (m)(5) or (6) of this 

section, you must report the information 

required in that paragraph no later than 

the date 2 years following the date 

specified in § 98.3(b) introductory text. 

■ 60. Amend § 98.238 by: 

■ a. Adding a definition for 

‘‘Centralized oil production site’’ in 

alphabetical order; 

■ b. Revising the definitions for 

‘‘Compressor mode’’ and ‘‘Compressor 

source’’; 

■ c. Adding a definition for 

‘‘Compressor station’’ in alphabetical 

order; 

■ d. Removing the second definition for 

‘‘Facility with respect to natural gas 

distribution for purposes of reporting 

under this subpart and for the 

corresponding subpart A requirements’’; 

■ e. Revising the definitions for ‘‘Flare 

stack emissions’’ and ‘‘Forced extraction 

of natural gas liquids’’; and 

■ f. Adding definitions for ‘‘Other large 

release event,’’ ‘‘Routed to combustion’’, 

‘‘Well blowout’’, and ‘‘Well release’’ in 

alphabetical order. 

The additions and revisions read as 

follows: 

§ 98.238 Definitions. 

* * * * * 

Centralized oil production site means 

any permanent combination of one or 

more hydrocarbon liquids storage tanks 

located on one or more contiguous or 

adjacent properties that does not also 

contain a permanent combination of one 

or more compressors that are part of the 

onshore petroleum and natural gas 

gathering and boosting facility that 

gathers hydrocarbon liquids from 

multiple well-pads. 

* * * * * 

Compressor mode means the 

operational and pressurized status of a 

compressor. For both centrifugal 

compressors and reciprocating 

compressors, ‘‘mode’’ refers to either: 

Operating-mode, standby-pressurizedmode, or not-operating-depressurizedmode. 

Compressor source means the source 

of certain venting or leaking emissions 

from a centrifugal or reciprocating 

compressor. For centrifugal 

compressors, ‘‘source’’ refers to 

blowdown valve leakage through the 

blowdown vent, unit isolation valve 

leakage through an open blowdown vent 

without blind flanges, wet seal oil 

degassing vents, and dry seal vents. For 

reciprocating compressors, ‘‘source’’ 

refers to blowdown valve leakage 

through the blowdown vent, unit 

isolation valve leakage through an open 

blowdown vent without blind flanges, 

and rod packing emissions. 

Compressor station means any 

permanent combination of one or more 

compressors located on one or more 

contiguous or adjacent properties that 

are part of the onshore petroleum and 

natural gas gathering and boosting 

facility that move natural gas at 

increased pressure through gathering 

pipelines or into or out of storage. 

* * * * * 

Flare stack emissions means CO2 in 

gas routed to a flare, CO2 from partial 

combustion of hydrocarbons in gas 

routed to a flare, CH4 emissions 

resulting from the incomplete 

combustion of hydrocarbons in gas 

routed to a flare, and N2O resulting from 

operation of a flare. 

Forced extraction of natural gas 

liquids means removal of ethane or 

higher carbon number hydrocarbons 

existing in the vapor phase in natural 

gas, by removing ethane or heavier 

hydrocarbons derived from natural gas 

into natural gas liquids by means of a 

forced extraction process. Forced 

extraction processes include but are not 

limited to refrigeration, absorption (lean 

oil), cryogenic expander, and 

combinations of these processes. Forced 

extraction does not include natural gas 

dehydration, the collection or gravity 

separation of water or hydrocarbon 

liquids from natural gas at ambient 

temperature or heated above ambient 

temperatures, the condensation of water 

or hydrocarbon liquids through passive 

reduction in pressure or temperature, a 

Joule-Thomson valve, a dew point 

depression valve, or an isolated or 

standalone Joule-Thomson skid. 

* * * * * 

Other large release event means an 

unplanned, unexpected, and 

uncontrolled release to the atmosphere 

of gas, liquids, or mixture thereof, from 

wells and/or other equipment that result 

in emissions for which there are no 

methodologies in § 98.233 to 

appropriately estimate these emissions. 

Other large release events include, but 

are not limited to, well blowouts, well 

releases, pressure relief valve releases 

from process equipment other than 

onshore production and onshore 

petroleum and natural gas gathering and 

boosting storage tanks, and releases that 

occur as a result of an accident, 

equipment rupture, fire, or explosion. 

Other large release events also include 

failure of equipment or equipment 

components such that a single 

equipment leak or release has emissions 

that exceed the emissions calculated for 


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that source using applicable methods in 

§ 98.233 by the threshold in § 98.233(y). 

* * * * * 

Routed to combustion means, for 

onshore petroleum and natural gas 

production facilities, natural gas 

distribution facilities, and onshore 

petroleum and natural gas gathering and 

boosting facilities, that emissions are 

routed to stationary or portable fuel 

combustion equipment specified in 

§ 98.232(c)(22), (i)(7), or (j)(12), as 

applicable. For all other industry 

segments in this subpart, routed to 

combustion means that emissions are 

routed to a stationary fuel combustion 

unit subject to subpart C of this part 

(General Stationary Fuel Combustion 

Sources). 

* * * * * 

Well blowout means a complete loss 

of well control for a long duration of 

time resulting in an emissions release. 

* * * * * 

Well release means a short duration of 

uncontrolled emissions release from a 

well followed by a period of controlled 

emissions release in which control 

techniques were successfully 

implemented. 

* * * * * 

■ 61. Revise table W–1A to subpart W 

of part 98 to read as follows: 

TABLE W–1A TO SUBPART W OF PART 98—DEFAULT WHOLE GAS EMISSION FACTORS FOR ONSHORE PETROLEUM AND

NATURAL GAS PRODUCTION FACILITIES AND ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND BOOSTING

FACILITIES

Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting Emission factor 

(scf/hour/component) 

Population Emission Factors—Pneumatic Device Vents and Pneumatic Pumps, Gas Service 1

Continuous Low Bleed Pneumatic Device Vents 2 .............................................................................................................. 6.8 

Continuous High Bleed Pneumatic Device Vents 2 ............................................................................................................. 21.2 

Intermittent Bleed Pneumatic Device Vents 2 ...................................................................................................................... 8.8 

Pneumatic Pumps 3 ............................................................................................................................................................. 13.3 

Population Emission Factors—Major Equipment, Gas Service 

Wellhead .............................................................................................................................................................................. 0.59 

Separator ............................................................................................................................................................................. 0.84 

Meters/Piping ....................................................................................................................................................................... 2.8 

Compressor ......................................................................................................................................................................... 10 

Acid Gas Removal Unit ....................................................................................................................................................... 2.4 

Dehydrator ........................................................................................................................................................................... 3.1 

Heater Treater ..................................................................................................................................................................... 0.12 

Storage Vessel .................................................................................................................................................................... 0.85 

Population Emission Factors—Major Equipment, Crude Service 

Wellhead .............................................................................................................................................................................. 0.14 

Separator ............................................................................................................................................................................. 0.43 

Meters/Piping ....................................................................................................................................................................... 2.5 

Compressor ......................................................................................................................................................................... 10 

Acid Gas Removal Unit ....................................................................................................................................................... 2.4 

Dehydrator ........................................................................................................................................................................... 3.1 

Heater Treater ..................................................................................................................................................................... 0.35 

Storage Vessel .................................................................................................................................................................... 0.56 

Population Emission Factors—Gathering Pipelines by Material Type 4

Protected Steel .................................................................................................................................................................... 0.91 

Unprotected Steel ................................................................................................................................................................ 8.0 

Plastic/Composite ................................................................................................................................................................ 0.27 

Cast Iron .............................................................................................................................................................................. 8.2 

1For multi-phase flow that includes gas, use the gas service emission factors. 

2Emission factor is in units of ‘‘scf/hour/device.’’ 

3Emission factor is in units of ‘‘scf/hour/pump.’’ 

4Emission factors are in units of ‘‘scf/hour/mile of pipeline.’’ 

Table W–1B to Subpart W of Part 98— 

Default Average Component Counts for 

Major Onshore Natural Gas Production 

Equipment and Onshore Petroleum and 

Natural Gas Gathering and Boosting 

Equipment for Reporting Year 2022 and 

Prior Reporting Years 

■ 62. Revise the table heading for table 

W–1B to subpart W of part 98 to read 

as set forth above. 

Table W–1C to Subpart W of Part 98— 

Default Average Component Counts for 

Major Crude Oil Production Equipment 

for Reporting Year 2022 and Prior 

Reporting Years 

■ 63. Revise the table heading for table 

W–1C to subpart W of part 98 to read 

as set forth above. 

Table W–1D to Subpart W of Part 98— 

Designation of Eastern and Western 

U.S. for Reporting Year 2022 and Prior 

Reporting Years 

■ 64. Revise the table heading for table 

W–1D to subpart W of part 98 to read 

as set forth above. 

■ 65. Revise table W–1E to subpart W of 

part 98 to read as follows: 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37101 

TABLE W–1E TO SUBPART W OF PART 98—DEFAULT WHOLE GAS LEAKER EMISSION FACTORS FOR ONSHORE

PETROLEUM AND NATURAL GAS PRODUCTION AND ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND BOOSTING

Equipment components 

Emission factor 

(scf/hour/component) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(i) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(ii) 

If you survey 

using any of the 

methods in 

§ 98.234(a)(1), (3), 

or (5) 

Leaker Emission Factors—All Components, Gas Service 1

Valve .......................................................................................................................... 4.9 3.5 16 

Flange ........................................................................................................................ 4.1 2.2 11 

Connector (other) ....................................................................................................... 1.3 0.8 7.9 

Open-Ended Line 2 .................................................................................................... 2.8 1.9 10 

Pressure Relief Valve ................................................................................................ 4.5 2.8 13

Pump Seal ................................................................................................................. 3.7 1.4 23 

Other 3 ........................................................................................................................ 4.5 2.8 15 

Leaker Emission Factors—All Components, Oil Service 

Valve .......................................................................................................................... 3.2 2.2 9.2 

Flange ........................................................................................................................ 2.7 1.4 11 

Connector (other) ....................................................................................................... 1.0 0.6 9.1 

Open-Ended Line ....................................................................................................... 1.6 1.1 6.6 

Pump 4 ....................................................................................................................... 3.7 2.6 15 

Other 3 ........................................................................................................................ 3.1 2.0 2.9 

1For multi-phase flow that includes gas, use the gas service emission factors. 

2The open-ended lines component type includes blowdown valve and isolation valve leaks emitted through the blowdown vent stack for centrifugal and reciprocating compressors. 3 ‘‘Others’’ category includes any equipment leak emission point not specifically listed in this table, as specified in § 98.232(c)(21) and (j)(10). 

4The pumps component type in oil service includes agitator seals. 

■ 66. Remove table W–2 to subpart W of 

part 98 and add table W–2A and table 

W–2B to subpart W of part 98 in 

numerical order to read as follows: 

TABLE W–2A TO SUBPART W OF PART 98—DEFAULT TOTAL HYDROCARBON LEAKER EMISSION FACTORS FOR ONSHORE

NATURAL GAS PROCESSING

Onshore natural gas processing plants 

Emission factor 

(scf/hour/component) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(i) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(ii) 

If you survey 

using any of the 

methods in 

§ 98.234(a)(1), (3), 

or (5) 

Leaker Emission Factors—Compressor Components, Gas Service 

Valve 1 ........................................................................................................................ 14.84 9.51 61 

Connector .................................................................................................................. 5.59 3.58 23 

Open-Ended Line ....................................................................................................... 17.27 11.07 71 

Pressure Relief Valve ................................................................................................ 39.66 25.42 163 

Meter .......................................................................................................................... 19.33 12.39 79 

Other 2 ........................................................................................................................ 4.1 2.63 17 

Leaker Emission Factors—Non-Compressor Components, Gas Service 

Valve 1 ........................................................................................................................ 6.42 4.12 26 

Connector .................................................................................................................. 5.71 3.66 23 

Open-Ended Line ....................................................................................................... 11.27 7.22 46 

Pressure Relief Valve ................................................................................................ 2.01 1.29 8.2 

Meter .......................................................................................................................... 2.93 1.88 12 

Other 2 ........................................................................................................................ 4.1 2.63 17 

1Valves include control valves, block valves and regulator valves. 

2Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table. 


jspears on DSK121TN23PROD with PROPOSALS2
37102 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

TABLE W–2B TO SUBPART W OF PART 98—DEFAULT WHOLE GAS POPULATION EMISSION FACTORS FOR ONSHORE

NATURAL GAS PROCESSING

Population emission factors—gas service onshore natural gas processing 

Emission factor 

(scf whole gas/ 

hour/device) 

Continuous Low Bleed Pneumatic Device Vents .......................................................................................................................... 6.8 

Continuous High Bleed Pneumatic Device Vents ......................................................................................................................... 32.4 

Intermittent Bleed Pneumatic Device Vents .................................................................................................................................. 2.3 

■ 67. Revise table W–3A to subpart W 

of part 98 to read as follows: 

TABLE W–3A TO SUBPART W OF PART 98—DEFAULT TOTAL HYDROCARBON LEAKER EMISSION FACTORS FOR ONSHORE

NATURAL GAS TRANSMISSION COMPRESSION

Onshore natural gas transmission compression 

Emission factor 

(scf/hour/component) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(i) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(ii) 

If you survey 

using any of the 

methods in 

§ 98.234(a)(1), (3), 

or (5) 

Leaker Emission Factors—Compressor Components, Gas Service 

Valve 1 ........................................................................................................................ 14.84 9.51 61 

Connector .................................................................................................................. 5.59 3.58 23 

Open-Ended Line ....................................................................................................... 17.27 11.07 71 

Pressure Relief Valve ................................................................................................ 39.66 25.42 163 

Meter or Instrument ................................................................................................... 19.33 12.39 79 

Other 2 ........................................................................................................................ 4.1 2.63 17 

Leaker Emission Factors—Non-Compressor Components, Gas Service 

Valve 1 ........................................................................................................................ 6.42 4.12 26 

Connector .................................................................................................................. 5.71 3.66 23 

Open-Ended Line ....................................................................................................... 11.27 7.22 46 

Pressure Relief Valve ................................................................................................ 2.01 1.29 8.2 

Meter or Instrument ................................................................................................... 2.93 1.88 12 

Other 2 ........................................................................................................................ 4.1 2.63 17 

1Valves include control valves, block valves and regulator valves. 

2Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table, as specified in 

§ 98.232(e)(8). 

■ 68. Revise the table heading and table 

W–3B to subpart W of part 98 to read 

as follows: 

TABLE W–3B TO SUBPART W OF PART 98—DEFAULT WHOLE GAS POPULATION EMISSION FACTORS FOR ONSHORE

NATURAL GAS TRANSMISSION COMPRESSION

Population emission factors—gas service onshore natural gas transmission compression 

Emission factor 

(scf whole gas/ 

hour/device) 

Continuous Low Bleed Pneumatic Device Vents .......................................................................................................................... 6.8 

Continuous High Bleed Pneumatic Device Vents ......................................................................................................................... 32.4 

Intermittent Bleed Pneumatic Device Vents .................................................................................................................................. 2.3 

■ 69. Revise table W–4A to subpart W 

of part 98 to read as follows: 


jspears on DSK121TN23PROD with PROPOSALS2
Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37103 

TABLE W–4A TO SUBPART W OF PART 98—DEFAULT TOTAL HYDROCARBON LEAKER EMISSION FACTORS FOR

UNDERGROUND NATURAL GAS STORAGE

Underground natural gas storage 

Emission factor 

(scf/hour/component) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(i) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(ii) 

If you survey 

using any of the 

methods in 

§ 98.234(a)(1), (3), 

or (5) 

Leaker Emission Factors—Storage Station, Gas Service 

Valve 1 ........................................................................................................................ 14.84 9.51 61 

Connector (other) ....................................................................................................... 5.59 3.58 23 

Open-Ended Line ....................................................................................................... 17.27 11.07 71 

Pressure Relief Valve ................................................................................................ 39.66 25.42 163 

Meter and Instrument ................................................................................................ 19.33 12.39 79 

Other 2 ........................................................................................................................ 4.1 2.63 17 

Leaker Emission Factors—Storage Wellheads, Gas Service 

Valve 1 ........................................................................................................................ 4.5 3.2 18 

Connector (other than flanges) .................................................................................. 1.2 0.7 4.9 

Flange ........................................................................................................................ 3.8 2.0 16 

Open-Ended Line ....................................................................................................... 2.5 1.7 10 

Pressure Relief Valve ................................................................................................ 4.1 2.5 17

Other 2 ........................................................................................................................ 4.1 2.5 17 

1Valves include control valves, block valves and regulator valves. 

2Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table, as specified in 

§ 98.232(f)(6) and (8). 

■ 70. Revise the table heading and table 

W–4B to subpart W of part 98 to read 

as follows: 

TABLE W–4B TO SUBPART W OF PART 98—DEFAULT POPULATION EMISSION FACTORS FOR UNDERGROUND NATURAL

GAS STORAGE

Underground natural gas storage Emission factor 

(scf/hour/component) 

Total Hydrocarbon Population Emission Factors—Storage Wellheads, Gas Service 

Connector ............................................................................................................................................................................ 0.01 

Valve .................................................................................................................................................................................... 0.1 

Pressure Relief Valve .......................................................................................................................................................... 0.17 

Open-Ended Line ................................................................................................................................................................. 0.03 

Whole Gas Population Emission Factors—Other Components, Gas Service 

Continuous Low Bleed Pneumatic Device Vents 1 .............................................................................................................. 6.8 

Continuous High Bleed Pneumatic Device Vents 1 ............................................................................................................. 32.4 

Intermittent Bleed Pneumatic Device Vents 1 ...................................................................................................................... 2.3 

1Emission Factor is in units of ‘‘scf whole gas/hour/device.’’ 

■ 71. Revise table W–5A to subpart W 

of part 98 to read as follows: 


jspears on DSK121TN23PROD with PROPOSALS2
37104 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

TABLE W–5A TO SUBPART W OF PART 98—DEFAULT METHANE LEAKER EMISSION FACTORS FOR LIQUEFIED NATURAL

GAS (LNG) STORAGE

LNG storage 

Emission factor 

(scf/hour/component) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(i) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(ii) 

If you survey 

using any of the 

methods in 

§ 98.234(a)(1), (3), 

or (5) 

Leaker Emission Factors—LNG Storage Components, LNG Service 

Valve .......................................................................................................................... 1.19 0.23 4.9 

Pump Seal ................................................................................................................. 4.00 0.73 16 

Connector .................................................................................................................. 0.34 0.11 1.4 

Other 1 ........................................................................................................................ 1.77 0.99 7.3 

Leaker Emission Factors—LNG Storage Components, Gas Service 

Valve 2 ........................................................................................................................ 14.84 9.51 61 

Connector .................................................................................................................. 5.59 3.58 23 

Open-Ended Line ....................................................................................................... 17.27 11.07 71 

Pressure Relief Valve ................................................................................................ 39.66 25.42 163 

Meter and Instrument ................................................................................................ 19.33 12.39 79 

Other 3 ........................................................................................................................ 4.1 2.63 17 

1 ‘‘Other’’ equipment type for components in LNG service should be applied for any equipment type other than connectors, pumps, or valves. 

2Valves include control valves, block valves and regulator valves. 

3 ‘‘Other’’ equipment type for components in gas service should be applied for any equipment type other than valves, connectors, flanges, 

open-ended lines, pressure relief valves, and meters and instruments, as specified in § 98.232(g)(6) and (7). 

■ 72. Revise table W–6A to subpart W 

of part 98 to read as follows: 

TABLE W–6A TO SUBPART W OF PART 98—DEFAULT METHANE LEAKER EMISSION FACTORS FOR LNG IMPORT AND

EXPORT EQUIPMENT

LNG import and export equipment 

Emission factor 

(scf/hour/component) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(i) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(ii) 

If you survey 

using any of the 

methods in 

§ 98.234(a)(1), (3), 

or (5) 

Leaker Emission Factors—LNG Terminals Components, LNG Service 

Valve .......................................................................................................................... 1.19 0.23 4.9 

Pump Seal ................................................................................................................. 4.00 0.73 16. 

Connector .................................................................................................................. 0.34 0.11 1.4 

Other 1 ........................................................................................................................ 1.77 0.99 7.3 

Leaker Emission Factors—LNG Terminals Components, Gas Service 

Valve 2 ........................................................................................................................ 14.84 9.51 61 

Connector .................................................................................................................. 5.59 3.58 23 

Open-Ended Line ....................................................................................................... 17.27 11.07 71 

Pressure Relief Valve ................................................................................................ 39.66 25.42 163 

Meter and Instrument ................................................................................................ 19.33 12.39 79 

Other 3 ........................................................................................................................ 4.1 2.63 17 

1 ‘‘Other’’ equipment type for components in LNG service should be applied for any equipment type other than connectors, pumps, or valves. 

2Valves include control valves, block valves and regulator valves. 

3 ‘‘Other’’ equipment type for components in gas service should be applied for any equipment type other than valves, connectors, flanges, 

open-ended lines, pressure relief valves, and meters and instruments, as specified in § 98.232(h)(7) and (8). 

■ 73. Revise table W–7 to subpart W of 

part 98 to read as follows: 


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TABLE W–7 TO SUBPART W OF PART 98—DEFAULT TOTAL HYDROCARBON LEAKER EMISSION FACTORS FOR ONSHORE

NATURAL GAS PROCESSING

Natural gas distribution 

Emission factor 

(scf/hour/component) 

If you survey 

using method 21 

as specified in 

§ 98.234(a)(2)(i) 

If you survey 

using any of the 

methods in 

§ 98.234(a)(1), (3), 

or (5) 

Leaker Emission Factors—Transmission-Distribution Transfer Station1 Components, Gas Service 

Connector .................................................................................................................................................... 1.69 6.7 

Block Valve .................................................................................................................................................. 0.557 2.3 

Control Valve ............................................................................................................................................... 9.34 38 

Pressure Relief Valve .................................................................................................................................. 0.27 1.1 

Orifice Meter ................................................................................................................................................ 0.212 0.87 

Regulator ..................................................................................................................................................... 0.772 3.2 

Open-ended Line ......................................................................................................................................... 26.131 107 

1Excluding customer meters. 

■ 74. Add table W–8 to subpart W of 

part 98 to read as follows: 

TABLE W–8 TO SUBPART W OF PART 98—DEFAULT METHANE POPULATION EMISSION FACTORS FOR NATURAL GAS

DISTRIBUTION

Natural gas distribution Emission factor 

(scf/hour/component) 

Population Emission Factors—Below Grade Transmission-Distribution Transfer Station Components and Below Grade MeteringRegulating Station1 Components, Gas Service 2

Below Grade T–D Transfer Station ..................................................................................................................................... 0.30 

Below Grade M&R Station .................................................................................................................................................. 0.30 

Population Emission Factors—Distribution Mains, Gas Service 3

Unprotected Steel ................................................................................................................................................................ 1.2 

Protected Steel .................................................................................................................................................................... 2.3 

Plastic .................................................................................................................................................................................. 0.45 

Cast Iron .............................................................................................................................................................................. 2.8 

Population Emission Factors—Distribution Services, Gas Service 4

Unprotected Steel ................................................................................................................................................................ 0.086 

Protected Steel .................................................................................................................................................................... 0.0077 

Plastic .................................................................................................................................................................................. 0.0016 

Copper ................................................................................................................................................................................. 0.03 

1Excluding customer meters. 

2Emission Factor is in units of ‘‘scf/hour/station.’’ 

3Emission Factor is in units of ‘‘scf/hour/mile.’’ 

4Emission Factor is in units of ‘‘scf/hour/number of services.’’ 

■ 75. Add table W–9 to subpart W of 

part 98 in numerical order to read as 

follows: 

TABLE W–9 TO SUBPART W OF PART

98—DEFAULT METHANE EMISSION

FACTORS FOR NATURAL GAS-FIRED

COMPRESSOR-DRIVERS

Compressor-driver 

engine design class 

Emission 

factor 

(kg CH4/mmBtu) 

2-stroke lean-burn 0.658 

4-stroke lean-burn 0.522 

4-stroke rich-burn .. 0.045 

Subpart X—Petrochemical Production 

■ 76. Amend § 98.243 by revising 

paragraphs (b)(3) and (d)(5) to read as 

follows: 

§ 98.243 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(3) For each flare, calculate CO2, CH4, 

and N2O emissions using the 

methodology specified in § 98.253(b). 

* * * * * 

(d) * * * 

(5) For each flare, calculate CO2, CH4, 

and N2O emissions using the 

methodology specified in § 98.253(b). 

■ 77. Amend § 98.244 by revising 

paragraph (b)(4)(iii) to read as follows: 

§ 98.244 vMonitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(4) * * * 

(iii) ASTM D2505–88 (Reapproved 

2004)e1 Standard Test Method for 

Ethylene, Other Hydrocarbons, and 

Carbon Dioxide in High-Purity Ethylene 


jspears on DSK121TN23PROD with PROPOSALS2
37106 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

by Gas Chromatography (incorporated 

by reference, see § 98.7). 

* * * * * 

■ 78. Amend § 98.246 by revising 

paragraphs (a) introductory text, (a)(2) 

and (5), (a)(13) and (15), (b)(7) and (8), 

(c) introductory text, and (c)(3) and (4) 

and adding paragraph (c)(6) to read as 

follows: 

§ 98.246 Data reporting requirements. 

* * * * * 

(a) If you use the mass balance 

methodology in § 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 EDC produced that is 

used in 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 

§ 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 of 

§ 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, report the annual 

average molecular weight of the 

measurements or determinations, 

conducted according to § 98.243(c)(3) or 

(4). Report the annual average molecular 

weight in units of kg per kg mole. 

(b) * * * 

(7) Information listed in § 98.256(e) of 

subpart Y of this part 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 § 98.243(d), 

you must report under this subpart the 

information listed in paragraphs (c)(1) 

through (c)(6) of this section. 

* * * * * 

(3) Information listed in § 98.256(e) of 

subpart Y of this part 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). 

* * * * * 

(6) Name and annual quantity (in 

metric tons) of each product produced 

in each process unit. 

Subpart Y—Petroleum Refineries 

■ 79. Amend § 98.253 by: 

■ a. Revising paragraph (b) introductory 

text, paragraph (c) introductory text, and 

paragraph (e) introductory text; 

■ b. Revising Equation Y–18b in 

paragraph (i)(2); 

■ c. Revising parameters ‘‘Mwater’’ and 

‘‘Hwater’’ of Equation Y–18b in 

paragraph (i)(2); 

■ d. Adding parameter ‘‘fcoke’’ to 

Equation Y–18b in paragraph (i)(2); and 

■ e. Revising parameter ‘‘Msteam’’ of 

Equation Y–18f in paragraph (i)(5). 

The revisions and addition read as 

follows: 

§ 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 

GHG emissions calculations with the 

exception of the following, which may 

be excluded as applicable: (1) gas used 

for the flare pilots, and (2) 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 (c)(5) of this 

section. 

* * * * * 

(e) For catalytic reforming units, 

calculate the CO2 emissions from coke 

burn-off using the applicable methods 

described in paragraphs (e)(1) through 

(e)(3) of this section and calculate the 

CH4 and N2O emissions using the 

methods described in paragraphs (c)(4) 

and (c)(5) of this section, respectively. 

* * * * * 

(i) * * * 

(2) * * * 

* * * * * 

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). 

* * * * * 

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. 

* * * * * 

(5) * * * 

* * * * * 

Msteam = Mass of steam generated and 

released per decoking cycle (metric tons/ 

cycle) as determined in paragraph (i)(4) 

of this section. 

* * * * * 

■ 80. Amend § 98.254 by revising 

paragraph (d) introductory text and 


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Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37107 

paragraph (e) introductory text to read 

as follows: 

§ 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 § 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 § 98.3(g)(5). 

* * * * * 

■ 81. Amend § 98.256 by revising 

paragraph (k)(6) to read as follows: 

§ 98.256 Data reporting requirements. 

* * * * * 

(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 of this 

subpart). 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. 

* * * * * 

■ 82. Amend § 98.257 by: 

■ a. Revising paragraphs (b)(45), (46), 

and (53); and 

■ b. Removing and reserving paragraphs 

(b)(54), (55), and (56). 

The revisions read as follows: 

§ 98.257 Records that must be retained. 

* * * * * 

(b) * * * 

(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 in 

§ 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 in § 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 in 

§ 98.253) for each delayed coking unit. 

* * * * * 

Subpart BB—Silicon Carbide 

Production 

■ 83. Amend § 98.286 by revising the 

introductory text and adding paragraph 

(c) to read as follows: 

§ 98.286 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

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. 

■ 84. Amend § 98.287 by revising the 

introductory text and adding paragraph 

(d) to read as follows: 

§ 98.287 Records that must be retained. 

In addition to the records required by 

§ 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 § 98.286(c). 

Subpart DD—Electrical Transmission 

and Distribution Equipment Use 

■ 85. Amend § 98.300 by revising 

paragraphs (a) introductory text and 

(a)(3) and (7) to read as follows: 

§ 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: 

* * * * * 

(3) Switchgear, including closedpressure and hermetically sealedpressure switchgear and gas-insulated 

lines containing fluorinated GHGs, 

including but not limited to SF6 and 

PFCs. 

* * * * * 

(7) Other containers of fluorinated 

GHG, including but not limited to SF6 

and PFCs. 

* * * * * 

■ 86. Revise § 98.301 to read as follows: 

§ 98.301 Reporting threshold. 

(a) You must report GHG emissions 

under this subpart if you are an electric 

power system as defined in § 98.308 and 

your facility meets the requirements of 

§ 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, you 

must calculate emissions of each 

fluorinated GHG, including but not 

limited to SF6 and PFCs, and then sum 

the emissions of each fluorinated GHG 


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resulting from the use of electrical 

transmission and distribution 

equipment for threshold applicability 

purposes using Equation DD–1 of this 

subpart. 

Where: 

E = Annual emissions for threshold 

applicability purposes (metric tons 

CO2e). 

NCEPS,j = the total nameplate capacity of 

insulating gas j-containing equipment 

(excluding hermetically sealed-pressure 

equipment) located within the facility 

plus the total nameplate capacity of 

insulting gas j-containing equipment 

(excluding hermetically sealed-pressure 

equipment) that is not located within the 

facility but is under common ownership 

or control 

GHGi,w = The weight fraction of fluorinated 

GHG i in 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 in subpart A of this part is not 

required to report emissions under 

subpart DD of this part unless the total 

estimated emissions from fluorinated 

gas, including but not limited to SF6 

and PFCs, containing equipment located 

at the facility, as calculated in Equation 

DD–2 for comparison to the 25,000 

metric ton CO2e per year emission 

threshold in Table A–3 meets or exceeds 

25,000 tons CO2e. 

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 insulating gas j containing 

equipment (excluding hermetically 

sealed-pressure equipment) located 

within the facility 

GHGi,w = The weight fraction of fluorinated 

GHG i in insulating gas j in the gas 

insulated equipment included in 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. 

■ 87. Revise § 98.302 to read as follows: 

§ 98.302 GHGs to report. 

You must report emissions of each 

fluorinated GHG, including but not 

limited to SF6 and PFC, 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 

§ 98.300(a). For acquisitions of 

equipment containing or insulated with 

fluorinated GHG, you must report 

emissions from the equipment after the 

title to the equipment is transferred to 

the electric power transmission or 

distribution entity. 

■ 88. Revise § 98.303 to read as follows: 

§ 98.303 Calculating GHG emissions. 

(a) Mass-balance approach. Calculate 

the annual emissions of each fluorinated 

GHG (including but not limited to SF6

and PFC) using the mass-balance 

approach in Equation DD–3 of this 

section: 

Where: 

User Emissionsi = Emissions of fluorinated 

GHG i from the facility (pounds). 

GHGi,w = The weight fraction of fluorinated 

GHG i in 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 Insulating gas j Inventory = 

(pounds of insulating gas j stored in 

containers, but not in energized 

equipment, at the beginning of the year) 

¥ (pounds of insulating gas j stored in 

containers, but not in energized 

equipment, at the end of the year). 

Acquisitions of Insulating gas j = (pounds of 

each insulating gas j purchased from 

chemical producers or distributors in 

bulk) + (pounds of each insulating gas j 

purchased from equipment 

manufacturers or distributors with or 

inside equipment, including 

hermetically sealed-pressure switchgear) 

+ (pounds of each insulating gas j 

returned to facility after off-site 

recycling). 

Disbursements of Insulating gas j = (pounds 

of each insulating gas j in bulk and 

contained in equipment that is sold to 

other entities) + (pounds of each 

insulating gas j returned to suppliers) + 

(pounds of each insulating gas j sent off 

site for recycling) + (pounds of each 

insulating gas j sent off-site for 

destruction). 

Net Increase in Total Nameplate Capacity of 

Equipment Operated containing 

insulating gas j = (The Nameplate 

Capacity of new equipment containing 

insulating gas j in pounds, including 

hermetically sealed-pressure switchgear) 

¥ (Nameplate Capacity of retiring 

equipment containing insulating gas j in 

pounds, including hermetically sealedpressure switchgear). (Note that 


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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 (b)(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 

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 

(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 temperaturecompensated design operating pressure 

per manufacturer specifications and 

measure and calculate the total amount 

of covered 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 

covered 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 

covered insulating gas to the electrical 

equipment, and subtract the second 

value (after-transfer gas container 

weight) from the first value (prior-totransfer 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. 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) Record the initial system pressure 

and vessel temperature prior to 

removing any insulating gas. 

(ii) Convert the initial system pressure 

to a temperature-compensated initial 

system pressure by using the 

temperature/pressure curve for that 

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 less than 90 percent of 

the temperature-compensated design 

operating pressure specified by the 

manufacturer (in absolute terms), use 

Equation DD–4 to calculate the 

nameplate capacity based on the mass 

recorded under paragraph (b)(5)(vi) of 

this section. 

(iv) Follow one of the following 

processes, depending on the 

methodology being used to measure the 

amount of gas recovered: 

(A) Connect a mass flow meter 

between the electrical equipment and a 

gas cart; or 

(B) 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 the blank-off 

pressure unless the integrity of the 

electrical equipment has been 

compromised in such a way that air will 

be drawn into the electrical equipment 

and gas cart if the electrical equipment 

is drawn into a vacuum. If the integrity 

of the electrical equipment has been so 

compromised, recover the insulating gas 

until the pressure in the electrical 

equipment is no higher than zero 

pounds per square inch gauge (0 psig). 

(vi) Record the amount of insulating 

gas recovered (pounds), either based on 

the reading from the mass flow meter, 

or 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–4. 

(vii) If you are calculating the 

nameplate capacity pursuant to 

paragraph (b)(5)(iii)(B), use Equation 

DD–4 to do so. 


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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 temperaturecompensated 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 manufacturerspecified 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 usermeasured 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 °F. 

(iv) Scales must be certified by the 

manufacturer to be accurate and precise 

to within one percent of the true weight. 

■ 89. Amend § 98.304 by removing and 

reserving paragraph (a) and revising 

paragraphs (b)(1), (2), and (4). 

The revisions read as follows: 

§ 98.304 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(1) Review inputs to Equation DD–3 of 

this section 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. 

* * * * * 

(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 offsite recycling are also accounted for 

among the total additions. 

* * * * * 

■ 90. Revise § 98.305 to read as follows: 

§ 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. 

■ 91. Amend § 98.306 by revising 

paragraphs (a) introductory text, (d) 

through (l), and (n) introductory text 

and adding paragraphs (o) through (r) to 

read as follows: 

§ 98.306 Data reporting requirements. 

* * * * * 

(a) Nameplate capacity of equipment 

(pounds) containing each insulating gas: 

* * * * * 

(d) Pounds of each insulating gas 

stored in containers, but not in 

energized equipment, at the beginning 

of the year. 

(e) Pounds of each insulating gas 

stored in containers, but not in 

energized equipment, at the end of the 

year. 

(f) Pounds of each insulating gas 

purchased in bulk from chemical 

producers or distributors. 

(g) Pounds of each insulating gas 

purchased from equipment 

manufacturers or distributors with or 

inside equipment, including 

hermetically sealed-pressure switchgear. 

(h) Pounds of each insulating gas 

returned to facility after off-site 

recycling. 

(i) Pounds of each insulating gas in 

bulk and contained in equipment sold 

to other entities. 

(j) Pounds of each insulating gas 

returned to suppliers. 

(k) Pounds of each insulating gas sent 

off-site for recycling. 

(l) Pounds of each insulating gas sent 

off-site for destruction. 

* * * * * 

(n) The number of insulating gas 

containing pieces of equipment in each 

of the following equipment categories: 

* * * * * 

(o) 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 usermeasured 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 usermeasured nameplate capacity value 

during the year. 

(p) The total of the nameplate 

capacity values measured by the 


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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 usermeasured 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 usermeasured nameplate capacity value 

during the year. 

(q) For each unique insulating gas 

reported in paragraphs (a), (d) through 

(l), and (n) of this section, an ID number 

or other appropriate descriptor. 

(r) For each ID number or descriptor 

reported in paragraph (q) of this section 

for each unique insulating gas, the name 

(as required in § 98.3(c)(4)(iii)(G)(1)) and 

weight percent of each fluorinated gas 

in the insulating gas. 

■ 92. Revise § 98.307 to read as follows: 

§ 98.307 Records that must be retained. 

(a) In addition to the information 

required by § 98.3(g), you must retain 

records of the information reported and 

listed in § 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., closedpressure vs. hermetically sealedpressure). 

(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 temperatureadjusted 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. 

■ 93. Amend § 98.308 by revising the 

definition of ‘‘Facility’’ and adding in 

alphabetical order definitions for 

‘‘Energized’’, ‘‘Insulating gas’’, ‘‘New 

equipment’’, and ‘‘Retired equipment’’ 

to read as follows: 

§ 98.308 Definitions. 

* * * * * 

Facility, with respect to an electric 

power system, means the electric power 

system as defined in this paragraph. 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. 

* * * * * 

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 arcquenching gas in electrical equipment. 

New equipment, for the purposes of 

this subpart, means any gas insulated 

equipment, including hermeticallysealed pressure switchgear, that is not 

energized at the beginning of the 

reporting year, but is energized at the 

end of the reporting year. This includes 

equipment 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). 

* * * * * 

Retired equipment, for the purposes of 

this subpart, means any gas insulated 

equipment, including hermeticallysealed pressure switchgear, that is 

energized at the beginning of the 

reporting year, but is not energized at 

the end of the reporting year. This 

includes equipment 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 

■ 94. Amend § 98.323 by revising 

parameter ‘‘MCFi’’ of Equation FF–3 in 

paragraph (b) introductory text to read 

as follows: 

§ 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. 

* * * * * 

■ 95. Amend § 98.326 by revising 

paragraph (t) to read as follows: 

§ 98.326 Data reporting requirements. 

* * * * * 

(t) Mine Safety and Health 

Administration (MSHA) identification 

number for this coal mine. 

Subpart GG—Zinc Production 

■ 96. Amend § 98.333 by revising 

paragraph (b)(1) introductory text to 

read as follows: 


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§ 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 of 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 of § 98.183. 

* * * * * 

■ 97. Amend § 98.336 by adding 

paragraph (a)(6) and revising paragraph 

(b)(6) to read as follows: 

§ 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 

■ 98. Amend § 98.343 by revising 

paragraph (a)(2) to read as follows: 

§ 98.343 Calculating GHG emissions. 

(a) * * * 

(2) For years when material-specific 

waste quantity data are available, apply 

Equation HH–1 of 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 of 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. 

* * * * * 

■ 99. Amend § 98.346 by adding 

paragraphs (i)(6)(i) and (ii) to read as 

follows: 

§ 98.346 Data reporting requirements. 

* * * * * 

(i) * * * 

(6) * * * 

(i) The percentage of total recovered 

CH4 that is sent to each measurement 

location (decimal, must total to 1 across 

all measurement locations at the 

facility). 

(ii) For each measurement location, 

the percentage of total recovered CH4

that is sent to a flare, a landfill gas to 

energy project, or an unknown option if 

gas is sent off-site for destruction and 

the type of destruction technology is 

unknown (decimal, must total to 1 for 

each measurement location). 

* * * * * 

■ 100. Revise table HH–1 to subpart HH 

of part 98 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) .................................................................................... 0.17 ................................................ Weight fraction, wet basis. 

k (precipitation plus recirculated leachate a <20 inches/year) ................ 0.055 .............................................. yr¥1

k (precipitation plus recirculated leachate a 20–40 inches/year) ............ 0.111 .............................................. yr¥1

k (precipitation plus recirculated leachate a >40 inches/year) ................ 0.142 .............................................. yr¥1

DOC and k values—Modified bulk MSW option 

DOC (bulk MSW, excluding inerts and C&D waste) .............................. 0.27 ................................................ Weight fraction, wet basis. 

DOC (inerts, e.g., glass, plastics, metal, concrete) ................................ 0.00 ................................................ Weight fraction, wet basis. 

DOC (C&D waste) ................................................................................... 0.08 ................................................ Weight fraction, wet basis. 

k (bulk MSW, excluding inerts and C&D waste) ..................................... 0.02 to 0.057 b ............................... yr¥1

k (inerts, e.g., glass, plastics, metal, concrete) ...................................... 0.00 ................................................ yr¥1

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, plastics, metal, cement) .................................. 0.00 ................................................ Weight fraction, wet basis. 

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


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TABLE HH–1 TO SUBPART HH OF PART 98—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS—Continued 

Factor Default value Units 

DOC and k values—Waste composition option 

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, metal, concrete) ...................................... 0.00 ................................................ yr¥1

k (uncharacterized MSW) ........................................................................ 0.055 to 0.142 ............................... yr¥1

Other parameters—All MSW landfills 

MCF ......................................................................................................... 1..

DOCF ....................................................................................................... 0.5.

F .............................................................................................................. 0.5.

OX ........................................................................................................... See Table HH–4 of 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 0.142 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. 

Subpart OO—Suppliers of Industrial 

Greenhouse Gases 

■ 101. Amend § 98.416 by revising 

paragraphs (c)(6) and (7) and (d)(4) and 

adding paragraph (k) to read as follows: 

§ 98.416 Data reporting requirements. 

* * * * * 

(c) * * * 

(6) Harmonized tariff system (HTS) 

code of the fluorinated GHGs, 

fluorinated HTFs, or nitrous oxide 

shipped. 

(7) Customs entry summary number 

and importer number for each shipment. 

* * * * * 

(d) * * * 

(4) Harmonized tariff system (HTS) 

code of the fluorinated GHGs, 

fluorinated HTFs, or nitrous oxide 

shipped. 

* * * * * 

(k) For nitrous oxide, saturated 

perfluorocarbons, and sulfur 

hexafluoride, report the end use(s) for 

which each GHG is transferred and the 

aggregated annual quantity of that GHG 

in metric tons that is transferred to that 

end use application, if known. 

Subpart PP— Suppliers of Carbon 

Dioxide 

■ 102. Amend § 98.420 by adding 

paragraph (a)(4) to read as follows: 

§ 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. 

* * * * * 

■ 103. Amend § 98.422 by adding 

paragraph (e) to read as follows: 

§ 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 onsite heat and/or electricity generation, 

where applicable. 

■ 104. Amend § 98.423 by revising 

paragraphs (a)(3)(i) introductory text 

and (a)(3)(ii) introductory text to read as 

follows: 

§ 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 in 

paragraph (a)(3). 

* * * * * 

(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. 

* * * * * 

■ 105. Amend § 98.426 by adding 

paragraph (i) to read as follows: 

§ 98.426 Data reporting requirements. 

* * * * * 

(i) If you capture a CO2 stream at a 

facility with a DAC process unit, report 

the annual quantity of on-site and offsite 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) 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. 


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(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. 

(ii) If electricity is sourced from onsite 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. 

(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 onsite 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. 

■ 106. Amend § 98.427 by revising 

paragraph (a) to read as follows: 

§ 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 SS—Electrical Equipment 

Manufacture or Refurbishment 

■ 107. Revise § 98.450 to read as 

follows: 

§ 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 gascontaining 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. 

■ 108. Revise § 98.451 to read as 

follows: 

§ 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 § 98.2(a)(2). To calculate total annual 

GHG emissions for comparison to the 

25,000 metric ton CO2e per year 

emission threshold in § 98.2(a)(2), 

follow the requirements of § 98.2(b), 

with one exception. Instead of following 

the requirement of § 98.453 to calculate 

emissions from electrical equipment 

manufacture or refurbishment, you must 

calculate emissions of each fluorinated 

GHG, including but not limited to SF6 

and PFCs, and then sum the emissions 

of each fluorinated GHG resulting from 

manufacturing and refurbishing 

electrical equipment using Equation SS– 

1 of this subpart. 

Where: 

E = Annual production process emissions for 

threshold applicability purposes (metric 

tons CO2e). 

Pj = Total annual purchases of insulating gas 

j (lbs). 

GHGi,w = The weight fraction of fluorinated 

GHG i in insulating gas j if 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. 


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i = fluorinated GHG contained in the 

electrical transmission and distribution 

equipment. 

0.000453592 = conversion factor from lbs to 

metric tons. 

■ 109. Amend § 98.452 by revising 

paragraph (a) to read as follows: 

§ 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. 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. 

* * * * * 

■ 110. Amend § 98.453 by: 

■ a. Revising paragraph (a); 

■ b. Removing and reserving paragraph 

(b); and 

■ c. Revising paragraphs (c) through (g), 

(h) introductory text, and (i). 

The revisions read as follows: 

§ 98.453 Calculating GHG emissions. 

(a) For each electrical equipment 

manufacturer or refurbisher, estimate 

the annual emissions of each fluorinated 

GHG using the mass-balance approach 

in Equation SS–2 of this section: 

Where: 

User emissionsi = Annual emissions of each 

fluorinated GHG i (pounds). 

GHGi,w = The weight fraction of fluorinated 

GHG i in 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 insulating gas j Inventory = 

(Pounds of insulating gas j stored in 

containers at the beginning of the year) 

¥ (Pounds of insulating gas j stored in 

containers at the end of the year). 

Acquisitions of insulating gas j = (Pounds of 

each insulating gas j purchased from 

chemical producers or suppliers in bulk) 

+ (Pounds of each insulating gas j 

returned by equipment users) + (Pounds 

of each insulating gas j returned to site 

after off-site recycling). 

Disbursements of insulating gas j = (Pounds 

of each insulating gas j contained in new 

equipment delivered to customers) + 

(Pounds of each insulating gas j 

delivered to equipment users in 

containers) + (Pounds of each insulating 

gas j returned to suppliers) + (Pounds of 

each insulating gas j sent off site for 

recycling) + (Pounds of each insulating 

gas j sent off-site for destruction). 

* * * * * 

(c) Estimate the disbursements of each 

insulating gas j (including, but not 

limited to SF6 and PFCs) 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–3 of this 

section: 

Where: 

DGHG = The annual disbursement of each 

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 each 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 (including, but not 

limited to SF6 and PFCs) 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–4 of this section: 

Where: 

Qp = The mass of each 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 each 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 each insulating gas 

j (including, but not limited to SF6 and 

PFCs) disbursed to customers in new 

equipment or cylinders over the period 

p is determined using a flowmeter, 

estimate this quantity using Equation 

SS–5 of this section: 


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Where: 

Qp = The mass of each insulating gas j 

(including, but not limited to SF6 and 

PFCs) 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 each insulating gas j that 

has flowed through the flowmeter during 

the period p. 

EL = The mass of each 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 each 

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–6 of this 

section: 

Where: 

EL = The mass of each fluorinated GHG 

(including, but not limited to SF6 and 

PFCs) or fluorinated GHG mixture 

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 each 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 (h)(2) of this section. 

* * * * * 

(i) Estimate the annual emissions of 

each 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–7 of this section: 

Where: 

EI = Total annual emissions of each 

insulating gas j from equipment 

installation at electric transmission or 

distribution facilities. 

GHGi,w = The weight fraction of fluorinated 

GHG i in insulating gas j if 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 each 

insulating gas j, in pounds, used to fill 

equipment during equipment installation 

at electric transmission or distribution 

facilities. 

MC = The total annual mass of each 

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. 

■ 111. Amend § 98.454 by removing and 

reserving paragraph (a) and revising 

paragraphs (b), (d) through (f), and (h)(1) 

through (4). 

The revisions read as follows: 

§ 98.454 Monitoring and QA/QC 

requirements. 

* * * * * 

(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 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 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. 

* * * * * 

(d) For purposes of Equations SS–6 of 

this subpart, 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–6 of 

this subpart. 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 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 insulating gas emitted 

downstream of the container or 

flowmeter during the period p. 

(f) If the mass of each 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 


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Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37117 

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. 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. 

* * * * * 

(h) * * * 

(1) Review inputs to Equation SS–2 of 

this subpart 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 insulating gas may be 

calculated as negative. 

(3) Ensure that for each insulating gas, 

the beginning-of-year inventory matches 

the end-of-year inventory from the 

previous year. 

(4) Ensure that for each insulating gas, 

in addition to the insulating gas 

purchased from bulk gas distributors, 

the insulating gas returned from 

equipment users with or inside 

equipment and the insulating gas 

returned from off-site recycling are also 

accounted for among the total additions. 

■ 112. Amend § 98.456 by revising 

paragraphs (a) through (k) and (n) 

through (s) and adding paragraphs (u) 

and (v) to read as follows: 

§ 98.456 Data reporting requirements. 

* * * * * 

(a) Pounds of each insulating gas 

stored in containers at the beginning of 

the year. 

(b) Pounds of each insulating gas 

stored in containers at the end of the 

year. 

(c) Pounds of each insulating gas 

purchased in bulk. 

(d) Pounds of each insulating gas 

returned by equipment users with or 

inside equipment. 

(e) Pounds of each 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 insulating gas 

returned to suppliers. 

(i) Pounds of each insulating gas sent 

off site for destruction. 

(j) Pounds of each insulating gas sent 

off site to be recycled. 

(k) The nameplate capacity of the 

equipment, in pounds, delivered to 

customers with insulating gas inside, if 

different from the quantity in paragraph 

(f) of this section. 

* * * * * 

(n) The total number of fill operations 

for each hose and valve combination, or, 

FCi of Equation SS–6 of this subpart. 

(o) If the mass of each insulating gas 

disbursed to customers in new 

equipment over the period p is 

determined according to the methods 

required in § 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 insulating gas 

disbursed to customers in new 

equipment over the period p is 

determined according to the methods 

required in § 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–7 of 

this subpart. 

(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–7 of this subpart. 

(s) The nameplate capacity of the 

equipment, in pounds, installed at offsite electric power transmission or 

distribution locations used to determine 

emissions from installation, or NI, of 

Equation SS–7 of this subpart. 

* * * * * 

(u) For each unique insulating gas 

reported in paragraphs (a) through (j) 

and (o) through (r) of this section, an ID 

number or other appropriate descriptor. 

(v) For each ID number or descriptor 

reported in paragraph (u) of this section 

for each unique insulating gas, the name 

(as required in § 98.3(c)(4)(iii)(G)(1)) and 

weight percent of each fluorinated gas 

in the insulating gas. 

■ 113. Revise § 98.458 to read as 

follows: 

§ 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. 

Subpart UU—Injection of Carbon 

Dioxide 

■ 114. Amend § 98.470 by redesignating 

paragraph (c) as paragraph (d) and 

adding new paragraph (c) to read as 

follows: 

§ 98.470 Definition of the source category. 

* * * * * 

(c) If you report under subpart VV of 

this part for a well or group of wells, 

you are not required to report under this 

subpart for that well or group of wells. 

* * * * * 

■ 115. Add subpart VV 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. 


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37118 Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 

Subpart VV—Geologic Sequestration 

of Carbon Dioxide With Enhanced Oil 

Recovery Using ISO 27916 

§ 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 International 

Standards Organization (ISO) standard 

designated as CSA/ANSI ISO 

27916:2019 (incorporated by reference, 

see § 98.7) as a method of quantifying 

geologic sequestration of CO2 in 

association with EOR operations. 

(2) You are not reporting under 

subpart UU of this part. 

(3) 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 § 98.2(a)(1) 

or (a)(2). 

§ 98.481 Reporting threshold. 

(a) You must report under this subpart 

if your CO2-EOR project uses CSA/ANSI 

ISO 27916:2019 (incorporated by 

reference, see § 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 § 98.2(i) do 

not apply to this subpart. Once a CO2- 

EOR project becomes subject to the 

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 27916:2019. 

(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. 

§ 98.482 GHGs to report. 

You must report the following from 

Clause 8 of CSA/ANSI ISO 27916:2019 

(incorporated by reference, see § 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. 

§ 98.483 Calculating CO2 geologic 

sequestration. 

You must calculate CO2 sequestered 

using the following quantification 

principles from Clause 8.2 of CSA/ANSI 

ISO 27916:2019 (incorporated by 

reference, see § 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 VV–1 of this section). 

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 

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 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), 

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 (c)(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 VV–2 of this 

section. 

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. 


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Federal Register / Vol. 87, No. 118 / Tuesday, June 21, 2022 / Proposed Rules 37119 

§ 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 27916:2019 

(incorporated by reference, see § 98.7). 

§ 98.485 Procedures for estimating 

missing data. 

Whenever the value of a parameter is 

unavailable or the quality assurance 

procedures set forth in § 98.484 cannot 

be followed, you must follow the 

procedures set forth in Clause 9.2 of 

CSA/ANSI ISO 27916:2019 

(incorporated by reference, see § 98.7). 

§ 98.486 Data reporting requirements. 

In addition to the information 

required by § 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

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 27916:2019 (incorporated by 

reference, see § 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). 

(2) The methods used to estimate 

missing data and the amounts estimated 

as described in Clause 9.2. 

(3) The approach and method for 

quantification utilized by the operator, 

including accuracy, precision, and 

uncertainties (see Clause 8 and Annex 

B). 

(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). 

(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. 

(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. 

§ 98.487 Records that must be retained. 

You must follow the record retention 

requirements specified by § 98.3(g). In 

addition to the records required by 

§ 98.3(g), you must comply with the 

record retention requirements in Clause 

9.1 of CSA/ANSI ISO 27916:2019 

(incorporated by reference, see § 98.7). 

§ 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)), 

establishes that the EOR complex is 

adequate to provide safe, long-term 

containment of CO2, and includes sitespecific 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 

27916:2019 (incorporated by reference, 

see § 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). 

(2) The initial containment assurance 

(see Clause 6.1.2). 

(3) The monitoring program (see 

Clause 6.2). 

(4) The quantification method to be 

used (see Clause 8 and Annex B). 

(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). 

(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. 

§ 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. 

(a) Additional terms and definitions 

are provided in Clause 3 of CSA/ANSI 

ISO 27916:2019 (incorporated by 

reference, see § 98.7). 

(b) All references in this subpart 

preceded by the word Clause refer to the 

Clauses in CSA/ANSI ISO 27916:2019. 

[FR Doc. 2022–09660 Filed 6–17–22; 8:45 am] 

BILLING CODE 6560–50–P 


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