1

MEMORANDUM

FROM: Rachel Schmeltz, U.S. EPA, Climate Change Division

TO: Docket EPA-HQ-OAR-2012-0934

DATE: March 1, 2013

SUBJECT: Table of 2013 Revisions to the Greenhouse Gas Reporting Rule 

1.0 INTRODUCTION

The 2009 final GHG reporting rule (2009 final rule) was signed by EPA Administrator 

Lisa Jackson on September 22, 2009 and published in the Federal Register on October 30, 2009 

(74 FR 56260, October 30, 2009). The 2009 final rule, which became effective on December 29, 

2009, included reporting of GHGs from various facilities and suppliers, consistent with the 2008 

Consolidated Appropriations Act. Subsequent notices were published in 2010 finalizing the 

requirements for subparts T, FF, II, and TT (75 FR 39736, July 12, 2010), subpart W (75 FR 

74458, November 20, 2010), subparts I, L, DD, QQ, and SS (75 FR 74774, December 1, 2010), 

and subparts RR and UU (75 FR 75060, December 1, 2010). These requirements are contained 

in 40 CFR part 98.The rule does not require control of GHGs, rather it only requires that sources 

above certain threshold levels monitor and report emissions and other related data.

Since promulgation of the rule, the EPA has identified a number of technical issues that 

need to be corrected and specific portions of the Mandatory Greenhouse Gases Reporting Rule 

(hereafter referred to as ―Part 98‖) that need to be clarified. The EPA is proposing to amend 

specific provisions in the Mandatory Reporting of Greenhouse Gases Rule to better reflect 

industry practices and improvements in climate research, correct technical and editorial errors

that have been identified since promulgation, and to clarify or update certain provisions that have 

been the subject of questions from reporting entities. 

The purpose of this memorandum is to provide a detailed list of each change proposed in 

this action. The table in section 3.0 contains a list of each change proposed, the rule language for 
2

the current requirement, and the proposed language. A brief explanation of the reason for the 

change is included for those items that are not specifically addressed in the preamble for this 

proposal. These changes are minor clarifications of the requirements text to better reflect EPA’s 

intent, simple corrections to calculation terms or cross-references that do not revise the output of 

the calculations, harmonizing changes within a subpart (such as changes to terminology), simple 

editorial and minor error corrections, or removal of redundant text. In total, these changes do not 

represent a change in reporting burden. Also available in the docket for this action is a set of 

documents in redline strikeout format for each section of Part 98 for which EPA is proposing 

changes. 

2.0 SUMMARY OF CHANGES INCLUDED 

EPA is proposing changes for the subparts identified in the table below. Significant 

changes that are not detailed in this memorandum include changes to tables for several subparts. 

The amended tables are available in the redline document for the individual subpart and as 

attachments to this memorandum. Tables that have been changed include: Table A-1, A-6, C-1, 

C-2, AA-1, AA-2, HH-1, HH-2, new Table HH-4, MM-1 NN-1, NN-2, and TT-1.

Subpart

A- General Provision

C- General Stationary Fuel Combustion Sources

E - Adipic Acid Production

G – Ammonia Manufacturing

H – Cement production

K –Ferroalloy Production

L –Fluorinated Gas Production

N – Glass Production

O - HCFC-22 Production and HFC-23 Destruction

P – Hydrogen Production

Q - Iron & Steel Production

S – Lime Manufacturing

V- Nitric Acid Production

X – Petrochemical Production 

Y – Petroleum Refineries

Z - Phosphoric Acid Production

AA - Pulp & Paper Manufacturing

BB - Silicon Carbide Production

DD - Electrical Transmission and Distribution Equipment Use
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Subpart

FF - Underground Coal Mines

HH – Municipal Solid Waste Landfills

II - Industrial Wastewater Treatment

MM- Suppliers of Petroleum Products

NN – Suppliers of Natural Gas and Natural Gas Liquids

PP – Suppliers of Carbon Dioxide

QQ - Importers and Exporters of Fluorinated Greenhouse Gases Contained in PreCharged Equipment or Closed Cell Foams

RR - Geologic Sequestration of Carbon Dioxide

SS - Electrical Equipment Manufacture or Refurbishment

TT - Industrial Waste Landfills 

UU - Injection of Carbon Dioxide

3.0 SUMMARY OF TECHNICAL CORRECTIONS AND OTHER AMENDMENTS

The following table summarizes the amendments proposed for various subparts of Part 98

which are being addressed by the proposed 2013 Revisions to the Greenhouse Gas Reporting 

Rule. 
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Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

A 98.3(c)(1) 98.3(c)(1) Facility name or supplier name (as 

appropriate), and physical street address of the 

facility or supplier, including the city, State, and zip 

code.

98.3(c)(1) Facility name or supplier name (as 

appropriate), and physical street address of the 

facility or supplier, including the city, State, and zip 

code. If the facility does not have a physical street 

address, then the facility must provide the latitude 

and longitude representing the location of facility 

operations in decimal degree format. This must be 

provided in a comma-delimited ―latitude, longitude‖ 

coordinate pair reported in decimal degrees to at 

least four digits to the right of the decimal. 

See preamble text for explanation

A 98.3(c)(11) (None) (viii) The facility or supplier must refer to the 

reporting instructions of the electronic GHG 

reporting tool regarding standardized conventions for 

the naming of a parent company. 

See preamble text for explanation

A 98.3(c )(13) (None) (13) ORIS code for each power generation unit that 

has been assigned an ORIS code by the Energy 

Information Administration. 

See preamble text for explanation

A 98.3(h)(4) (4) Notwithstanding paragraphs (h)(1) and (h)(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 

(h)(2) of this section. If the Administrator receives a 

request for extension of the 45-day period, by e-mail 

to an address prescribed by the Administrator, at 

least two days prior to the expiration of the 45-day 

period, and the Administrator does not respond to the 

request by the end of such period, the extension 

request is deemed to be automatically granted for 30 

more days. During the automatic 30-day extension, 

the Administrator will determine what extension, if 

any, beyond the automatic extension is reasonable 

and will provide any such additional extension.

(4) Notwithstanding paragraphs (h)(1) and (h)(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 

(h)(2) of this section. If the Administrator receives a 

request for extension of the 45-day period, by e-mail 

to an address prescribed by the Administrator prior 

to the expiration of the 45-day period, the extension 

request is deemed to be automatically granted for 30 

days. The Administrator may grant an additional 

extension beyond the automatic 30-day extension if 

the owner or operator submits a request for an 

additional extension and the request is received by 

the Administrator at least 5 business days 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 (h)(2) with 75 days. The 

See preamble text for explanation
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Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

Administrator will approve the extension request if 

the request demonstrates that it is not practicable to 

collect and process the data needed to resolve 

potential reporting errors identified pursuant to 

paragraphs (h)(1) or (h)(2) of this section within 75 

days. 

A 98.3(j)(3)(ii) (ii) Any subsequent extensions to the original request 

must be submitted to the Administrator within 4 

weeks of the owner or operator identifying the need 

to extend the request, but in any event no later than 4 

weeks before the date for the planned process 

equipment or unit shutdown that was provided in the 

original request.

(ii) Any subsequent extensions to the original request 

must be submitted to the Administrator within 4 

weeks of the owner or operator identifying the need 

to extend the request, but in any event no later than 4 

weeks before the date for the planned process 

equipment or unit shutdown that was provided in the 

original or most recently approved request.

Clarifies BAMM requirement.

A 98.3(k)(1) (None) (k) Revised Global Warming Potentials. 

(1) General. Starting with reporting year 2013, 

facilities and suppliers must use the revised GWPs in 

Table A-1 of this subpart, Global Warming 

Potentials (revised 2013), for calculating CO2e 

emissions for determining applicability to this part 

and for calculating CO2e emissions in annual GHG 

reports. 

See preamble text for explanation

A 98.3(k)(2) (None) (2) Special provision for reporting year 2013. A 

facility or supplier that was not subject a subpart of 

part 98 for reporting year 2012, but becomes subject 

a subpart due to a change in the GWP for one or 

more compounds in Table A-1 of this subpart, 

Global Warming Potentials (revised 2013), is not 

required to submit an annual GHG for reporting year 

2013. Such facilities or suppliers must start 

monitoring and collecting GHG data in compliance 

with this part starting on January 1, 2014, and submit 

an annual greenhouse gas report for reporting year 

2014 by March 31, 2015.

See preamble text for explanation

A 98.3(l) (None) (l) Special provision for best available monitoring See preamble text for explanation
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Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

methods in 2014. This paragraph applies to owners 

or operators of facilities or suppliers that first 

become subject to any subpart of part 98 due to an 

amendment to Table A-1 of this subpart, Global 

Warming Potentials (revised 2013).

A 98.3(l)(1) (None) (1) Best available monitoring methods. From 

January 1, 2014 to March 31, 2014, owners or 

operators subject to this paragraph may use best 

available monitoring methods for any parameter 

(e.g., fuel use, feedstock rates) that cannot 

reasonably be measured according to the monitoring 

and QA/QC requirements of a relevant subpart. The 

owner or operator must use the calculation 

methodologies and equations in the ―Calculating 

GHG Emissions‖ sections of each relevant subpart, 

but may use the best available monitoring method for 

any parameter for which it is not reasonably feasible 

to acquire, install, and operate a required piece of 

monitoring equipment by January 1, 2014. Starting 

no later than April 1, 2014, the owner or operator 

must discontinue using best available methods and 

begin following all applicable monitoring and 

QA/QC requirements of this part, except as provided 

in paragraph (l)(2) of this section. Best available 

monitoring methods means any of the following 

methods:

See preamble text for explanation

A 98.3(l)(1)(i)-

(iv)

(None) (i) Monitoring methods currently used by the facility 

that do not meet the specifications of a relevant 

subpart.

(ii) Supplier data.

(iii) Engineering calculations.

(iv) Other company records.

See preamble text for explanation

A 98.3(l)(2) (None) (2) Requests for extension of the use of best 

available monitoring methods. The owner or operator 

may submit a request to the Administrator to use one 

or more best available monitoring methods beyond 

March 31, 2014.

(i) Timing of request. The extension request must be 

submitted to EPA no later than January 31, 2014.

See preamble text for explanation
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Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

(ii) Content of request. Requests must contain the 

following information:

A 98.3(l)(2)(ii)(

A)

(None) (A) A list of specific items of monitoring 

instrumentation for which the request is being made 

and the locations where each piece of monitoring 

instrumentation will be installed.

See preamble text for explanation

A 98.3(l)(2)(ii)(

B)

(None) (B) Identification of the specific rule requirements 

(by rule subpart, section, and paragraph numbers) for 

which the instrumentation is needed.

See preamble text for explanation

A 98.3(l)(2)(ii)(

C)

(None) (C) A description of the reasons that the needed 

equipment could not be obtained and installed before 

April 1, 2014.

See preamble text for explanation

A 98.3(l)(2)(ii)(

D)

(None) (D) If the reason for the extension is that the 

equipment cannot be purchased and delivered by 

April 1, 2014, supporting documentation such as the 

date the monitoring equipment was ordered, 

investigation of alternative suppliers and the dates by 

which alternative vendors promised delivery, 

backorder notices or unexpected delays, descriptions 

of actions taken to expedite delivery, and the current 

expected date of delivery.

See preamble text for explanation

A 98.3(l)(2)(ii)(

E)

(None) (E) If the reason for the extension is that the 

equipment cannot be installed without a process unit 

shutdown, include supporting documentation 

demonstrating that it is not practicable to isolate the 

equipment and install the monitoring instrument 

without a full process unit shutdown. Include the 

date of the most recent process unit shutdown, the 

frequency of shutdowns for this process unit, and the 

date of the next planned shutdown during which the 

monitoring equipment can be installed. If there has 

been a shutdown or if there is a planned process unit 

shutdown between [THE DATE OF PUBLICATION 

OF THE FINAL RULE IN THE FEDERAL 

REGISTER] and April 1, 2014, include a 

justification of why the equipment could not be 

obtained and installed during that shutdown.

See preamble text for explanation

A 98.3(l)(2)(ii)(

F)

(None) (F) A description of the specific actions the facility 

will take to obtain and install the equipment as soon 

See preamble text for explanation
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Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

as reasonably feasible and the expected date by 

which the equipment will be installed and operating.

A 98.3(l)(2)(iii) (None) (iii) Approval criteria. To obtain approval, the owner 

or operator must demonstrate to the Administrator's 

satisfaction that it is not reasonably feasible to 

acquire, install, and operate a required piece of 

monitoring equipment by April 1, 2014. The use of 

best available methods under this subsection (l) will 

not be approved beyond December 31, 2014.

See preamble text for explanation

A 98.6 Continuous bleed means a continuous flow of 

pneumatic supply gas to the process measurement

device (e.g. level control, temperature control, 

pressure control) where the supply gas pressure is 

modulated by the process condition, and then flows 

to the valve controller where the signal is compared 

with the process set-point to adjust gas pressure in 

the valve actuator.

Continuous bleed means a continuous flow of 

pneumatic supply natural gas to the process control 

device (e.g. level control, temperature control, 

pressure control) where the supply gas pressure is 

modulated by the process condition, and then flows 

to the valve controller where the signal is compared 

with the process set-point to adjust gas pressure in 

the valve actuator.

Clarifies definition

A 98.6 Degasification system means the entirety of the 

equipment that is used to drain gas from 

underground and collect it at a common point, such 

as a vacuum pumping station. This includes all 

degasification wells and gob gas vent holes at the 

underground coal mine. Degasification systems 

include surface pre-mining, horizontal pre-mining, 

and post-mining systems.

Degasification system means the entirety of the 

equipment that is used to drain gas from 

underground coal mines. This includes all 

degasification wells and gob gas vent holes at the 

underground coal mine. Degasification systems 

include gob and premine surface drainage wells, gob 

and premine in-mine drainage wells, and in-mine 

gob and premine cross-measure borehole wells.

See preamble text for explanation

A 98.6 Intermittent bleed pneumatic devices mean 

automated flow control devices powered by 

pressurized natural gas and used for maintaining a 

process condition such as liquid level, pressure, 

delta-pressure and temperature. These are snapacting or throttling devices that discharge the full 

volume of the actuator intermittently when control 

action is necessary, but does not bleed continuously.

Intermittent bleed pneumatic devices mean 

automated flow control devices powered by 

pressurized natural gas and used for automatically 

maintaining a process condition such as liquid level, 

pressure, delta-pressure and temperature. These are 

snap-acting or throttling devices that discharge all or 

a portion of the full volume of the actuator 

intermittently when control action is necessary, but 

does not bleed continuously.

Clarifies definition

A 98.6 (None) Fluidized Bed Combustor (FBC) means a 

combustion technology (e.g., a fluidized bed boiler) 

where the maximum steady-state temperature 

See preamble text for explanation
9

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

reached within the combustor (excluding periods of 

startup, shutdown, and malfunction) during the 

combustion of solid fuels (e.g., coal, tire derived 

fuel, wood and wood residuals, agricultural 

byproducts, coke, municipal solid waste, or mixtures 

of such fuels) is less than or equal to 19,900 degrees 

F. 

A 98.6 Ventilation well or shaft means a well or shaft 

employed at an underground coal mine to serve as 

the outlet or conduit to move air from the ventilation 

system out of the mine.

Ventilation hole or shaft means a vent hole or shaft 

employed at an underground coal mine to serve as 

the outlet or conduit to move air from the ventilation 

system out of the mine.

See preamble text for explanation

A 98.6 Ventilation system means a system that is used to 

control the concentration of methane and other gases 

within mine working areas through mine ventilation, 

rather than a mine degasification system. A 

ventilation system consists of fans that move air 

through the mine workings to dilute methane 

concentrations. This includes all ventilation shafts 

and wells at the underground coal mine.

Ventilation system means a system that is used to 

control the concentration of methane and other gases 

within mine working areas through mine ventilation, 

rather than a mine degasification system. A 

ventilation system consists of fans that move air 

through the mine workings to dilute methane 

concentrations. 

See preamble text for explanation

A 98.6 98.6 No definition ORIS Code means the unique identifier assigned to 

each power plant in the National Electric Energy 

Data System (NEEDS). The ORIS code is a 4 digit 

number assigned by the Energy Information 

Administration (EIA) at US Department of Energy to 

power plants owned by utilities. 

Definition added for new term used in rule 

A Table A-1 Table A-1 See Appendix A for changes to Table A-1 See preamble text for explanation

A Table A-6 Table A-6 See Appendix A for changes to Table A-6 Changed numbering of two data elements for subpart 

HH

C 98.33(b)(1) (None) (viii) May be used for the combustion of a fuel listed 

in Table C-1 if the fuel is combusted in a unit with a 

maximum rated heat input capacity greater than 250 

mmBtu/hr (or, pursuant to §98.36(c)(3), in a group of 

units served by a common supply pipe, having at 

least one unit with a maximum rated heat input 

capacity greater than 250 mmBtu/hr), provided that 

both of the following conditions apply:

(A) The use of Tier 4 is not required.

(B) The fuel provides less than 10 percent of the 

See preamble text for explanation
10

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

annual heat input to the unit, or if §98.36(c)(3) 

applies, to the group of units served by a common 

supply pipe.

(ix) May not be used for the combustion of waste 

coal (i.e., waste anthracite (culm) and waste 

bituminous (gob)). 

C 98.33(b)(3)(ii

)(A)

(A) The use of Tier 1 or 2 is permitted, as described 

in paragraphs (b)(1)(iii), (b)(1)(v), and (b)(2)(ii) of 

this section.

(A) The use of Tier 1 or 2 is permitted, as described 

in paragraphs (b)(1)(iii), (b)(1)(v), (b)(1)(viii), and 

(b)(2)(ii) of this section.

Harmonizing change with addition of paragraph 

98.33(b)(1)(viii). 

C 98.33(e)(1)(ii

)

(ii) The procedures in paragraph (e)(5) of this 

section.

(ii) The procedures in paragraph (e)(4) of this 

section.

Corrects reference

C 98.33(e)(3)(iv

)(B)

(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 0.6 and 

for tires, use a default factor of 0.20.

(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 0.55 

and for tires, use a default factor of 0.20.

See preamble text for explanation

C

98.36(b)(3)

(3) Maximum rated heat input capacity of the unit in 

mmBtu/hr for boilers and process heaters only and 

relevant units of measure for other combustion units. 

(3) Maximum rated heat input capacity of the unit in 

mmBtu/hr. 

Standardize units of measure for all reporters. 

C 98.36(c)(3) (3) ...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. 

...

(3) ...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. ...

Consistency across the subpart

C Table C-1 Table C-1 See Appendix A for changes to Table C-1 See preamble text for explanation

C Table C-2 Table C-2 See Appendix A for changes to Table C-2 See preamble text for explanation

E 98.53(b)(3) (3) You must measure the adipic acid production rate 

during the test and calculate the production rate for 

the test period in metric tons per hour.

(3) You must measure the adipic acid production rate 

during the test and calculate the production rate for 

the test period in tons per hour.

Corrects a requirement for consistency throughout 

the subpart. 

E 98.53(d) (d) If any N2O abatement technology ―N‖ is located 

after your test point, you must determine the 

destruction efficiency according to paragraphs (d)(1), 

(2), or (3) of this section.

(d) If the adipic acid production unit exhausts to any 

N2O abatement technology ―N‖, you must determine 

the destruction efficiency according to paragraphs 

(d)(1), (d)(2), or (d)(3) of this section.

Clarifies requirement. 

E 98.53(e) (e) If any N2O abatement technology ―N‖ is located 

after your test point, you must determine the annual 

(e) If the adipic acid production unit exhausts to any 

N2O abatement technology ―N‖, you must determine 

Clarifies requirement.
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Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

amount of adipic acid produced while N2O

abatement technology ―N‖ is operating according to 

§98.54(f). Then you must calculate the abatement 

factor for N2O abatement technology ―N‖ according 

to Equation E–2 of this section.

the annual amount of adipic acid produced while 

N2O abatement technology ―N‖ is operating 

according to §98.54(f). Then you must calculate the 

abatement factor for N2O abatement technology ―N‖ 

according to Equation E–2 of this section.

E 98.53(e)

Equation E-2

Harmonizes equation with its definition. 

E 98.53(g)(1) DF = Destruction efficiency of N2O abatement 

technology ―N‖ (percent of N2O removed from vent 

stream).

DF = Destruction efficiency of N2O abatement 

technology ―N‖ (decimal fraction of N2O removed 

from vent stream).

Clarifies a calculation term. 

E 98.53(g)(1) AF = Abatement utilization factor of N2O abatement 

technology ―N‖ (percent of time that the abatement 

technology is operating).

AF = Abatement utilization factor of N2O abatement 

technology ―N‖ (decimal fraction of time that the 

abatement technology is operating).

Clarifies a calculation term. 

E 98.53(g)(2) DF1 = Destruction efficiency of N2O abatement 

technology 1 (percent of N2O removed from vent 

stream).

DF1 = Destruction efficiency of N2O abatement 

technology 1 (decimal fraction of N2O removed from 

vent stream).

Clarifies a calculation term. 

E 98.53(g)(2) AF1 = Abatement utilization factor of N2O abatement 

technology 1 (percent of time that abatement 

technology 1 is operating).

AF1 = Abatement utilization factor of N2O

abatement technology 1 (decimal fraction of time 

that abatement technology 1 is operating).

Clarifies a calculation term. 

E 98.53(g)(2) DF2 = Destruction efficiency of N2O abatement 

technology 2 (percent of N2O removed from vent 

stream).

DF2 = Destruction efficiency of N2O abatement 

technology 2 (decimal fraction of N2O removed from 

vent stream).

Clarifies a calculation term. 

E 98.53(g)(2) AF2 = Abatement utilization factor of N2O abatement 

technology 2 (percent of time that abatement 

technology 2 is operating).

AF2 = Abatement utilization factor of N2O

abatement technology 2 (decimal fraction of time 

that abatement technology 2 is operating).

Clarifies a calculation term. 

E 98.53(g)(2) DFN = Destruction efficiency of N2O abatement 

technology N (percent of N2O removed from vent 

stream).

DFN = Destruction efficiency of N2O abatement 

technology ―N‖ (decimal fraction of N2O removed 

from vent stream).

Clarifies a calculation term. 

E 98.53(g)(2) AFN = Abatement utilization factor of N2O

abatement technology N (percent of time that 

abatement technology N is operating).

AFN = Abatement utilization factor of N2O

abatement technology ―N‖ (decimal fraction of time 

that abatement technology N is operating).

Clarifies a calculation term. 

E 98.53(g)(3) DFN = Destruction efficiency of N2O abatement 

technology ―N‖ (percent of N2O removed from vent 

stream).

DFN = Destruction efficiency of N2O abatement 

technology ―N‖ (decimal fraction of N2O removed 

from vent stream).

Clarifies a calculation term. 

E 98.53(g)(3) AFN = Abatement utilization factor of N2O

abatement technology ―N‖ (percent of time that the 

AFN = Abatement utilization factor of N2O

abatement technology ―N‖ (decimal fraction of time 

Clarifies a calculation term. 
12

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

abatement technology is operating). that the abatement technology is operating).

E 98.53(g)(3) FCN = Fraction control factor of N2O abatement 

technology ―N‖ (percent of total emissions from unit 

―z‖ that are sent to abatement technology ―N‖).

FCN = Fraction control factor of N2O abatement 

technology ―N‖ (decimal fraction of total emissions 

from unit ―z‖ that are sent to abatement technology 

―N‖).

Clarifies a calculation term. 

E 98.54(e) (e) You must determine the monthly amount of 

adipic acid produced. You must also determine the 

monthly amount of adipic acid produced during 

which N2O abatement technology, located after the 

test point, is operating. These monthly amounts are 

determined according to the methods in paragraphs 

(c)(1) or (2) of this section.

(e) You must determine the monthly amount of 

adipic acid produced. You must also determine the 

monthly amount of adipic acid produced during 

which N2O abatement technology is operating. These 

monthly amounts are determined according to the 

methods in paragraphs (c)(1) or (c)(2) of this section.

Corrects a requirement for consistency throughout 

the subpart. 

E 98.54(f) (f) You must determine the annual amount of adipic 

acid produced. You must also determine the annual 

amount of adipic acid produced during which N2O

abatement technology located after the test point is 

operating. These are determined by summing the 

respective monthly adipic acid production quantities 

determined in paragraph (e) of this section.

(f) You must determine the annual amount of adipic 

acid produced. You must also determine the annual 

amount of adipic acid produced during which N2O

abatement technology is operating. These are 

determined by summing the respective monthly 

adipic acid production quantities determined in 

paragraph (e) of this section.

Corrects a requirement for consistency throughout 

the subpart. 

G 98.73(b)(4) (4) You must calculate the annual process CO2

emissions from each ammonia processing unit k at 

your facility summing emissions, as applicable from 

Equation G–1, G–2, and G–3 of this section using 

Equation G–4.

(4) You must calculate the annual process CO2

emissions from each ammonia processing unit k at 

your facility according to Equation G-4 of this 

section:

Clarifies calculation methodologies.

G 98.73(b)(4) 

Equation G-4

(Eq. G-4) Corrects a calculation term

G 98.73(b)(5)

Equation G-5 (Eq. G-5)

Corrects a calculation term

G 98.73(b)(5) ECO2k = Annual CO2 emissions from each ammonia 

processing unit (metric tons).

ECO2,k = Annual CO2 emissions from each ammonia 

processing unit k (metric tons).

Clarifies a calculation term. 

G 98.73(b)(5) n = Total number of ammonia processing units. j = Total number of ammonia processing units. Corrects a calculation term

G 98.75(b) (b) For missing feedstock supply rates or waste (b) For missing feedstock supply rates used to Correction to missing data procedures to remove 

ECO2,k CO2,G,k CO2,L,k CO2,S ,k

j

k

CO ECO k

1

2 2,
13

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

recycle stream used to determine monthly feedstock 

consumption or monthly waste recycle stream 

quantity, you must determine the best available 

estimate(s) of the parameter(s), based on all available 

process data.

determine monthly feedstock consumption , you 

must determine the best available estimate(s) of the 

parameter(s), based on all available process data.

reference to parameters that are no longer part of the 

regulations.

G 98.76(a) (a) If a CEMS is used to measure CO2 emissions, 

then you must report the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology and the following information in this 

paragraph (a):

(a) If a CEMS is used to measure CO2 emissions, 

then you must report the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology and the information in paragraphs 

(a)(1) and (a)(2) of this section:

Clarifies a requirement.

G 98.76(b) (b) If a CEMS is not used to measure emissions, then 

you must report the following information:

(b) If a CEMS is not used to measure emissions, then 

you must report all of the following information in 

this paragraph (b):

Clarifies that all information must be reported.

G 98.76(b)(13) (13) CO2 from the steam reforming of a hydrocarbon 

or the gasification of solid and liquid raw material at 

the ammonia manufacturing process unit used to 

produce urea and the method used to determine the 

CO2 consumed in urea production.

(13) Annual CO2 emissions (metric tons) from the 

steam reforming of a hydrocarbon or the gasification 

of solid and liquid raw material at the ammonia 

manufacturing process unit used to produce urea and 

the method used to determine the CO2 consumed in 

urea production.

Clarifies the units of the CO2 emissions.

H 98.86(a)(2) (2) Monthly cement production from each kiln at the 

facility.

(2)Annual facility cement production. See preamble text for explanation

K 98.113(d)(1)

Equation K-3

2000/2205 = Conversion factor to convert 

tons to metric tons.

2/2205 = Conversion factor to convert kg CH4/ton of 

product to metric tons CH4.

See preamble text for explanation

K 98.116(e)(2) No current requirement (2) Annual process CH4 emissions (in metric tons) 

from each EAF used for the production of any 

ferroalloy listed in Table K–1 of this subpart.

See preamble text for explanation
14

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

L 98.126(j) 

Introductory 

paragraph

(j) Special provisions for reporting years 2011 and 

2012 only. For reporting years 2011 and 2012, the 

owner or operator of a facility must comply with 

paragraphs (j)(1), (j)(2), and (j)(3) of this section.

(j) Special provisions for reporting years 2011, 2012, 

and 2013 only. For reporting years 2011, 2012, and 

2013, the owner or operator of a facility must 

comply with paragraphs (j)(1), (j)(2), and (j)(3) of 

this section.

See preamble text for explanation

L 98.126(j)(1) (1) Timing. The owner or operator of a facility is not 

required to report the data elements at 

§98.3(c)(4)(iii) and §98.126(a)(2), (a)(3), (a)(4), 

(a)(6), (b), (c), (d), (e), (f), (g), and (h) of this section 

until the later of March 31, 2014 or the date set forth 

for that data element at §98.3(c)(4)(vii) and Table A–

7 of Subpart A of this part.

(1) Timing. The owner or operator of a facility is not 

required to report the data elements at 

§98.3(c)(4)(iii) and §98.126(a)(2), (a)(3), (a)(4), 

(a)(6), (b), (c), (d), (e), (f), (g), and (h) of this section 

until the later of March 31, 2015 or the date set forth 

for that data element at §98.3(c)(4)(vii) and Table A–

7 of Subpart A of this part.

See preamble text for explanation

L 98.126(j)(3)(i

)

(i) If you choose to use a default GWP rather than 

your best estimate of the GWP for fluorinated GHGs 

whose GWPs are not listed in Table A–1 to this 

subpart, use a default GWP of 10,000 for fluorinated 

GHGs that are fully fluorinated GHGs and use a 

default GWP of 2000 for other fluorinated GHGs.

(i) If you choose to use a default GWP rather than 

your best estimate of the GWP for fluorinated GHGs 

whose GWPs are not listed in Table A–1 of subpart 

A of this part, use a default GWP of 10,000 for 

fluorinated GHGs that are fully fluorinated GHGs 

and use a default GWP of 2000 for other fluorinated 

GHGs.

Correction to referenced table

N 98.143

Introductory 

paragraph

You must calculate and report the annual process 

CO2 emissions from each continuous glass melting 

furnace using the procedure in paragraphs (a) and (b) 

of this section.

You must calculate and report the annual process 

CO2 emissions from each continuous glass melting 

furnace using the procedure in paragraphs (a) 

through (c) of this section.

Corrects reference

N 98.143(b) (b) For each continuous glass melting furnace that is 

not subject to the requirements in paragraph (a) of 

this section, calculate and report the process and 

combustion CO2 emissions from the glass melting 

furnace by using either the procedure in paragraph 

(b)(1) of this section or the procedure in paragraphs 

(b)(2) through (b)(7) of this section, except as 

specified in paragraph (c) of this section.

(b) For each continuous glass melting furnace that is 

not subject to the requirements in paragraph (a) of 

this section, calculate and report the process and 

combustion CO2 emissions from the glass melting 

furnace by using either the procedure in paragraph 

(b)(1) of this section or the procedure in paragraph 

(b)(2) of this section, except as specified in 

paragraph (c) of this section.

Corrects reference

N 98.143(b)(2)(

iv) 

MFi = Annual average mass fraction of carbonatebased mineral i in carbonate-based raw material i 

(percentage, expressed as a decimal).

MFi = Annual average decimal mass fraction of 

carbonate-based mineral i in carbonate-based raw 

material i.

Clarifies the equation term

N 98.143(b)(2)(

iv)

Fi = Fraction of calcination achieved for carbonatebased raw material i, assumed to be equal to 1.0 

(percentage, expressed as a decimal).

Fi = Decimal fraction of calcination achieved for 

carbonate-based raw material i, assumed to be equal 

to 1.0.

Clarifies the equation term

N 98.144(b) (b) You must measure carbonate-based mineral mass 

fractions at least annually to verify the mass fraction 

(b) You must measure carbonate-based mineral mass 

fractions at least annually to verify the mass fraction 

See preamble text for explanation
15

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

data provided by the supplier of the raw material; 

such measurements shall be based on sampling and 

chemical analysis using ASTM D3682–01 

(Reapproved 2006) Standard Test Method for Major 

and Minor Elements in Combustion Residues from 

Coal Utilization Processes (incorporated by 

reference, see §98.7) or ASTM D6349–09 Standard 

Test Method for Determination of Major and Minor 

Elements in Coal, Coke, and Solid Residues from 

Combustion of Coal and Coke by Inductively 

Coupled Plasma—Atomic Emission Spectrometry 

(incorporated by reference, see §98.7).

data provided by the supplier of the raw material; 

such measurements shall be based on sampling and 

chemical analysis using consensus standards that 

specify X-ray fluorescence. For measurements made 

in years prior to the emissions reporting year 2014, 

you may also use ASTM D3682–01 (Reapproved 

2006) Standard Test Method for Major and Minor 

Elements in Combustion Residues from Coal 

Utilization Processes (incorporated by reference, see 

§98.7) or ASTM D6349–09 Standard Test Method 

for Determination of Major and Minor Elements in 

Coal, Coke, and Solid Residues from Combustion of 

Coal and Coke by Inductively Coupled Plasma—

Atomic Emission Spectrometry (incorporated by 

reference, see §98.7).

N 98.146(b)(4) (4) Carbonate-based mineral mass fraction 

(percentage, expressed as a decimal) for each 

carbonate-based raw material charged to a 

continuous glass melting furnace.

(4) Carbonate-based mineral decimal mass fraction 

for each carbonate-based raw material charged to a 

continuous glass melting furnace.

Clarifies the requirement

N 98.146(b)(6) (6) The fraction of calcination achieved for each 

carbonate-based raw material, if a value other than 

1.0 is used to calculate process mass emissions of 

CO2.

(6) The decimal fraction of calcination achieved for 

each carbonate-based raw material, if a value other 

than 1.0 is used to calculate process mass emissions 

of CO2.

Clarifies the requirement

N 98.146(b)(7) (7) Method used to determine fraction of calcination. (7) Method used to determine decimal fraction of 

calcination.

Clarifies the requirement

N 98.147(b)(5) (5) The fraction of calcination achieved for each 

carbonate-based raw material (percentage, expressed 

as a decimal), if a value other than 1.0 is used to 

calculate process mass emissions of CO2.

(5) The decimal fraction of calcination achieved for 

each carbonate-based raw material, if a value other 

than 1.0 is used to calculate process mass emissions 

of CO2.

Clarifies the requirement

O 98.153(c) (c) For HCFC–22 production facilities that do not 

use a thermal oxidizer or that have a thermal oxidizer 

that is not directly connected to the HCFC–22 

production equipment, HFC–23 emissions shall be 

estimated using Equation O–4 of this section:

(c) For HCFC–22 production facilities that do not 

use a destruction device or that have a destruction 

device that is not directly connected to the HCFC–22 

production equipment, HFC–23 emissions shall be 

estimated using Equation O–4 of this section:

Harmonizing change for consistency of destruction 

device terminology within subpart.

O 98.153(d) (d) For HCFC–22 production facilities that use a 

thermal oxidizer connected to the HCFC–22 

production equipment, HFC–23 emissions shall be 

estimated using Equation O–5 of this section:

(Eq. O-5)

(d) For HCFC–22 production facilities that use a 

destruction device connected to the HCFC–22 

production equipment, HFC–23 emissions shall be 

estimated using Equation O–5 of this section:

(Eq. O-5)

Harmonizing change for consistency of destruction 

device terminology within subpart.
16

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

Where:

ED = Mass of HFC–23 emitted annually from 

thermal oxidizer (metric tons), calculated using 

Equation O–8 of this section.

Where:

ED = Mass of HFC–23 emitted annually from 

destruction device (metric tons), calculated using 

Equation O–8 of this section.

O 98.154(j) (j) The number of sources of equipment type t with 

screening values less than 10,000 ppmv shall be the 

difference between the number of leak sources of 

equipment type t that could emit HFC-23 and the 

number of sources of equipment type t with 

screening values greater than or equal to 10,000 

ppmv as determined under paragraph (h) of this 

section.

(j) The number of sources of equipment type t with 

screening values less than 10,000 ppmv shall be the 

difference between the number of leak sources of 

equipment type t that could emit HFC-23 and the 

number of sources of equipment type t with 

screening values greater than or equal to 10,000 

ppmv as determined under paragraph (i) of this 

section.

Correct paragraph reference.

O 98.156(c) (c) Each HFC-23 destruction facility shall report the

concentration (mass fraction) of HFC-23 measured at 

the outlet of the destruction device during the 

facility's annual HFC-23 concentration 

measurements at the outlet of the device.

(c) Each HFC-23 destruction facility shall report the 

concentration (mass fraction) of HFC-23 measured at 

the outlet of the destruction device during the 

facility's annual HFC-23 concentration 

measurements at the outlet of the device. If the 

concentration of HFC-23 is below the detection limit 

of the measuring device, report the detection limit 

and that the concentration is below the detection 

limit.

See preamble text for explanation

P 98.163(b) (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 (b)(3) of this section.

(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 (b)(3) 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 

See preamble text for explanation
17

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

obtained during the month as the monthly average.

P 98.163(b)(1) Fdstkn = Volume of the gaseous fuel and feedstock 

used in month n (scf (at standard conditions of 68 °F 

and atmospheric pressure) of fuel and feedstock).

CCn = Average carbon content of the gaseous fuel 

and feedstock, from the results of one or more 

analyses for month n (kg carbon per kg of fuel and 

feedstock). If measurements are taken more 

frequently than monthly, use the arithmetic average 

of measurement values within the month to calculate 

a monthly average.

MWn = Average molecular weight of the gaseous 

fuel and feedstock from the results of one or more 

analyses for month n (kg/kg-mole).

Fdstkn = Volume of the gaseous fuel or feedstock 

used in month n (scf (at standard conditions of 68 °F 

and atmospheric pressure) of fuel or feedstock).

CCn = Average carbon content of the gaseous fuel 

and feedstock for month n (kg carbon per kg of fuel 

or feedstock). 

MWn = Average molecular weight of the gaseous 

fuel or feedstock for month n (kg/kg-mole).

Clarifies equation terms

P 98.163(b)(2) Fdstkn = Volume of the liquid fuel and feedstock 

used in month n (gallons of fuel and feedstock).

CCn = Average carbon content of the liquid fuel and 

feedstock, from the results of one or more analyses 

for month n (kg carbon per gallon of fuel and 

feedstock).

Fdstkn =Volume of the liquid fuel or feedstock used 

in month n (gallons of fuel or feedstock).

CCn = Average carbon content of the liquid fuel or 

feedstock, for month n (kg carbon per gallon of fuel 

or feedstock).

Clarifies equation terms

P 98.163(b)(3) Fdstkn = Mass of solid fuel and feedstock used in 

month n (kg of fuel and feedstock).

CCn = Average carbon content of the solid fuel and 

feedstock, from the results of one or more analyses 

for month n (kg carbon per kg of fuel and feedstock).

Fdstkn = Mass of solid fuel or feedstock used in 

month n (kg of fuel or feedstock).

CCn = Average carbon content of the solid fuel or 

feedstock, for month n (kg carbon per kg of fuel or 

feedstock).

Clarifies equation terms

P 98.164(b)(3) (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 

delivered by bulk transport (e.g., by truck or rail).

(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). 

See preamble text for explanation

P 98.164(b)(4) (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 delivered by bulk 

transport (e.g., by truck or rail).

(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).

See preamble text for explanation
18

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

P 98.164(b)(5) (5) 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 continuous chromatographic analysis of the 

fuel and feedstock, provided that the gas 

chromatograph (GC) is operated, maintained, and 

calibrated according to the manufacturer's 

instructions; and the methods used for operation, 

maintenance, and calibration of the GC are 

documented in the written monitoring plan for the 

unit under §98.3(g)(5).

(5) 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).

See preamble text for explanation

P 98.164(c) (c) For units using the calculation methodologies 

described in this section, the records required under 

§98.3(g) must include both the company records and 

a detailed explanation of how company records are 

used to estimate the following:

(1) Fuel and feedstock consumption, when solid fuel 

and feedstock is combusted and a CEMS is not used 

to measure GHG emissions.

(2) Fossil fuel consumption, when, pursuant to 

§98.33(e), the owner or operator of a unit that uses 

CEMS to quantify CO2 emissions and that combusts 

both fossil and biogenic fuels separately reports the 

biogenic portion of the total annual CO2 emissions.

(3) Sorbent usage, if the methodology in §98.33(d) is 

used to calculate CO2 emissions from sorbent.

(c ) [Reserved] See preamble text for explanation

P 98.164(d) (d) The owner or operator must document the 

procedures used to ensure the accuracy of the 

estimates of fuel and feedstock usage and sorbent 

usage (as applicable) in paragraph (b) of this section,

including, but not limited to, calibration of weighing 

equipment, fuel and feedstock flow meters, and other 

measurement devices. The estimated accuracy of 

measurements made with these devices must also be 

recorded, and the technical basis for these estimates 

must be provided.

(d) [Reserved] See preamble text for explanation
19

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

P 98.166(a)(2) -

(a)(3)

(2) Annual quantity of hydrogen produced (metric 

tons) for each process unit and for all units 

combined.

(3) Annual quantity of ammonia produced (metric 

tons), if applicable, for each process unit and for all 

units combined.

(2) Annual quantity of hydrogen produced (metric 

tons) for each process unit.

(3) Annual quantity of ammonia produced (metric 

tons), if applicable for each process unit.

See preamble text for explanation

P 98.167(c ) (None) (c) For units using the calculation methodologies 

described 98.163(b), the records required under 

§98.3(g) must include both the company records and 

a detailed explanation of how company records are 

used to estimate the following:

(1) Fuel and feedstock consumption, when solid fuel 

and feedstock is combusted and a CEMS is not used 

to measure GHG emissions. 

(2) Fossil fuel consumption, when, pursuant to 

§98.33(e), the owner or operator of a unit that uses 

CEMS to quantify CO2 emissions and that combusts 

both fossil and biogenic fuels separately reports the 

biogenic portion of the total annual CO2 emissions. 

(3) Sorbent usage, if the methodology in §98.33(d) is 

used to calculate CO2 emissions from sorbent. 

See preamble text for explanation

P 98.167(d) (None) (d) The owner or operator must document the 

procedures used to ensure the accuracy of the 

estimates of fuel and feedstock usage and sorbent 

usage (as applicable) in 98.163(b), including, but not 

limited to, calibration of weighing equipment, fuel 

and feedstock flow meters, and other measurement 

devices. The estimated accuracy of measurements 

made with these devices must also be recorded, and 

the technical basis for these estimates must be 

provided. 

See preamble text for explanation

Q 98.170

Introductory 

paragraph

98.170 Definition of the source category.

The iron and steel production source category 

includes facilities with any of the following 

processes: taconite iron ore processing, integrated 

iron and steel manufacturing, cokemaking not 

colocated with an integrated iron and steel 

manufacturing process, and electric arc furnace 

(EAF) steelmaking not colocated with an integrated 

98.170 Definition of the source category.

The iron and steel production source category 

includes facilities with any of the following 

processes: taconite iron ore processing, integrated 

iron and steel manufacturing, cokemaking not 

colocated with an integrated iron and steel 

manufacturing process, direct reduction furnaces not 

collocated with an integrated iron and steel 

See preamble text for explanation
20

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

iron and steel manufacturing process. Integrated iron 

and steel manufacturing means the production of 

steel from iron ore or iron ore pellets. At a minimum, 

an integrated iron and steel manufacturing process 

has a basic oxygen furnace for refining molten iron 

into steel. Each cokemaking process and EAF 

process located at a facility with an integrated iron 

and steel manufacturing process is part of the 

integrated iron and steel manufacturing facility.

manufacturing process, and electric arc furnace 

(EAF) steelmaking not colocated with an integrated 

iron and steel manufacturing process. Integrated iron 

and steel manufacturing means the production of 

steel from iron ore or iron ore pellets. At a minimum, 

an integrated iron and steel manufacturing process 

has a basic oxygen furnace for refining molten iron 

into steel. Each cokemaking process and EAF 

process located at a facility with an integrated iron 

and steel manufacturing process is part of the 

integrated iron and steel manufacturing facility.

Q 98.173(b)(1)(

i)

(Csf) = Carbon content of the solid fuel, from the fuel 

analysis (percent by weight, expressed as a decimal 

fraction, e.g., 95% = 0.95).

(C0) = Carbon content of the greenball (taconite) 

pellets, from the carbon analysis results (percent by 

weight, expressed as a decimal fraction).

(Cp) = Carbon content of the fired pellets, from the 

carbon analysis results (percent by weight, expressed 

as a decimal fraction).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (percent by 

weight, expressed as a decimal fraction).

(Csf) = Carbon content of the solid fuel, from the fuel 

analysis (expressed as a decimal fraction).

(C0) = Carbon content of the greenball (taconite) 

pellets, from the carbon analysis results (expressed 

as a decimal fraction).

(Cp) = Carbon content of the fired pellets, from the 

carbon analysis results (expressed as a decimal 

fraction).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (expressed 

as a decimal fraction).

Clarifies equation terms

Q 98.173(b)(1)(

i)

(Fs) = Annual mass of the solid fuel combusted 

(metric tons).

(Fs) = Annual mass of the solid fuel used (metric 

tons).

Clarifies equation term

Q 98.173(b)(1)(

i)

(Fg) = Annual volume of the gaseous fuel combusted 

(scf).

(Fg) = Annual volume of the gaseous fuel used (scf). Clarifies equation term

Q 98.173(b)(1)(

i)

(Fl) = Annual volume of the liquid fuel combusted 

(gallons).

(Fl) = Annual volume of the liquid fuel used 

(gallons).

Clarifies equation term

Q 98.173(b)(1)(

ii),

(CIron) = Carbon content of the molten iron, from the 

carbon analysis results (percent by weight, expressed 

as a decimal fraction).

(CScrap) = Carbon content of the ferrous scrap, from 

the carbon analysis results (percent by weight, 

expressed as a decimal fraction).

(CFlux) = Carbon content of the flux materials, from 

the carbon analysis results (percent by weight, 

expressed as a decimal fraction).

(CCarbon) = Carbon content of the carbonaceous 

(CIron) = Carbon content of the molten iron, from the 

carbon analysis results (expressed as a decimal 

fraction).

(CScrap) = Carbon content of the ferrous scrap, from 

the carbon analysis results (expressed as a decimal 

fraction).

(CFlux) = Carbon content of the flux materials, from 

the carbon analysis results (expressed as a decimal 

fraction).

(CCarbon) = Carbon content of the carbonaceous 

Clarifies equation terms
21

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

materials, from the carbon analysis results (percent 

by weight, expressed as a decimal fraction).

(CSteel) = Carbon content of the steel, from the carbon 

analysis results (percent by weight, expressed as a 

decimal fraction).

(CSlag) = Carbon content of the slag, from the carbon 

analysis (percent by weight, expressed as a decimal 

fraction).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (percent by 

weight, expressed as a decimal fraction).

materials, from the carbon analysis results (expressed 

as a decimal fraction).

(CSteel) = Carbon content of the steel, from the carbon 

analysis results (expressed as a decimal fraction).

(CSlag) = Carbon content of the slag, from the carbon 

analysis (expressed as a decimal fraction).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (expressed 

as a decimal fraction).

Q 98.173(b)(1)(

iii)

(CCoal) = Carbon content of the coal, from the carbon 

analysis results (percent by weight, expressed as a 

decimal fraction).

(CCoke) = Carbon content of the coke, from the 

carbon analysis results (percent by weight, expressed 

as a decimal fraction).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (percent by 

weight, expressed as a decimal fraction).

(CCoal) = Carbon content of the coal, from the carbon 

analysis results (expressed as a decimal fraction).

(CCoke) = Carbon content of the coke, from the 

carbon analysis results (expressed as a decimal 

fraction).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (expressed 

as a decimal fraction).

Clarifies equation terms

Q 98.173(b)(1)(

iv)

(CFeed) = Carbon content of the mixed sinter feed 

materials that form the bed entering the sintering 

machine, from the carbon analysis results (percent by 

weight, expressed as a decimal fraction).

(CSinter) = Carbon content of the sinter pellets, from 

the carbon analysis results (percent by weight, 

expressed as a decimal fraction).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (percent by 

weight, expressed as a decimal fraction).

(CFeed) = Carbon content of the mixed sinter feed 

materials that form the bed entering the sintering 

machine, from the carbon analysis results (expressed 

as a decimal fraction).

(CSinter) = Carbon content of the sinter pellets, from 

the carbon analysis results (expressed as a decimal 

fraction).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (expressed 

as a decimal fraction).

Clarifies equation terms

Q 98.173(b)(1)(

iv)

(Fg) = Annual volume of the gaseous fuel combusted 

(scf).

(Fg) = Annual volume of the gaseous fuel used (scf). Clarifies equation term

Q 98.173(b)(1)(

v)

(v) For EAFs, estimate CO2 emissions using 

Equation Q-5 of this section. 

CO2=44/12*[(Iron)*(CIron)+(Scrap)*(CScrap)+(Flux)*(

Cf)+(Electrode)*(CElectrode)+(Carbon)*(Cc)-

(Steel)*(CSteel)-(Slag)*(CSlag)-(R)*(CR)

(v) For EAFs, estimate CO2 emissions using 

Equation Q-5 of this section. 

CO2=44/12*[(Iron)*(CIron)+(Scrap)*(CScrap)+(Flux)*(

CFlux)+(Electrode)*(CElectrode)+(Carbon)*(CCarbon)-

(Steel)*(CSteel)+(Fg)*(Cgf)*MW/MVC*0.001-

(Slag)*(CSlag)-(R)*(CR)]

See preamble text for explanation
22

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

Where:

CO2 = Annual CO2 mass emissions from the EAF 

(metric tons). 

44/12 = Ratio of molecular weights, CO2 to carbon.

(Iron) = Annual mass of direct reduced iron (if any) 

charged to the furnace (metric tons).

(CIron) = Carbon content of the direct reduced iron, 

from the carbon analysis results (percent by weight, 

expressed as a decimal fraction).

(Scrap) = Annual mass of ferrous scrap charged to 

the furnace (metric tons).

(CScrap) = Carbon content of the ferrous scrap, from 

the carbon analysis results (percent by weight, 

expressed as a decimal fraction).

(Flux) = Annual mass of flux materials (e.g., 

limestone, dolomite) charged to the furnace (metric 

tons).

(CFlux) = Carbon content of the flux materials, from 

the carbon analysis results (percent by weight, 

expressed as a decimal fraction).

(Electrode) = Annual mass of carbon electrode 

consumed (metric tons).

(CElectrode) = Carbon content of the carbon electrode, 

from the carbon analysis results (percent by weight,

expressed as a decimal fraction).

(Carbon) = Annual mass of carbonaceous materials 

(e.g., coal, coke) charged to the furnace (metric 

tons).

(CCarbon) = Carbon content of the carbonaceous 

materials, from the carbon analysis results (percent 

by weight, expressed as a decimal fraction).

(Steel) = Annual mass of molten raw steel produced 

by the furnace (metric tons).

(CSteel) = Carbon content of the steel, from the carbon 

analysis results (percent by weight, expressed as a 

decimal fraction).

(Slag) = Annual mass of slag produced by the 

furnace (metric tons).

Where:

CO2 = Annual CO2 mass emissions from the EAF 

(metric tons). 

44/12 = Ratio of molecular weights, CO2 to carbon.

(Iron) = Annual mass of direct reduced iron (if any) 

charged to the furnace (metric tons).

(CIron) = Carbon content of the direct reduced iron, 

from the carbon analysis results (expressed as a 

decimal fraction).

(Scrap) = Annual mass of ferrous scrap charged to 

the furnace (metric tons).

(CScrap) = Carbon content of the ferrous scrap, from 

the carbon analysis results (expressed as a decimal 

fraction).

(Flux) = Annual mass of flux materials (e.g., 

limestone, dolomite) charged to the furnace (metric 

tons).

(CFlux) = Carbon content of the flux materials, from 

the carbon analysis results (expressed as a decimal 

fraction).

(Electrode) = Annual mass of carbon electrode 

consumed (metric tons).

(CElectrode) = Carbon content of the carbon electrode, 

from the carbon analysis results (expressed as a 

decimal fraction).

(Carbon) = Annual mass of carbonaceous materials 

(e.g., coal, coke) charged to the furnace (metric 

tons).

(CCarbon) = Carbon content of the carbonaceous 

materials, from the carbon analysis results (expressed 

as a decimal fraction).

(Steel) = Annual mass of molten raw steel produced 

by the furnace (metric tons).

(CSteel) = Carbon content of the steel, from the carbon 

analysis results (expressed as a decimal fraction).

(Fg) = Annual volume of the gaseous fuel used (scf at 

60 degrees F and one atmosphere).
23

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

(CSlag) = Carbon content of the slag, from the carbon 

analysis results (percent by weight, expressed as a 

decimal fraction).

(R) = Annual mass of air pollution control residue 

collected (metric tons).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (percent by 

weight, expressed as a decimal fraction).

(Cgf) = Average carbon content of the gaseous fuel, 

from the fuel analysis results (kg C per kg of fuel).

(MW) = Molecular weight of the gaseous fuel 

(kg/kg-mole).

(MVC) = Molar volume conversion factor (836.6 scf 

per kg-mole at standard conditions of 60 degrees F 

and one atmosphere).

(0.001) = Conversion factor from kg to metric tons.

(Slag) = Annual mass of slag produced by the 

furnace (metric tons).

(CSlag) = Carbon content of the slag, from the carbon 

analysis results (expressed as a decimal fraction).

(R) = Annual mass of air pollution control residue 

collected (metric tons).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (expressed 

as a decimal fraction).

Q 98.173(b)(1)(

vi)

(vi) For decarburization vessels, estimate CO2

emissions using Equation Q-6 of this section. 

CO2=44/12*(Steel)*[(CSteelin)-(CSteelout)]-(R)*(CR)

Where:

CO2 = Annual CO2 mass emissions from the 

decarburization vessel (metric tons).

44/12 = Ratio of molecular weights, CO2 to carbon.

(Steel) = Annual mass of molten steel charged to the 

vessel (metric tons).

(CSteelin) = Carbon content of the molten steel before 

decarburization, from the carbon analysis results 

(percent by weight, expressed as a decimal fraction).

(CSteelout) = Carbon content of the molten steel after 

decarburization, from the carbon analysis results 

(percent by weight, expressed as a decimal fraction).

(R) = Annual mass of air pollution control residue 

collected (metric tons).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (percent by 

weight, expressed as a decimal fraction).

(vi) For decarburization vessels, estimate CO2

emissions using Equation Q-6 of this section. 

CO2=44/12*{(Steel)*[(CSteelin)-(CSteelout)]-(R)*(CR)}

Where:

CO2 = Annual CO2 mass emissions from the 

decarburization vessel (metric tons).

44/12 = Ratio of molecular weights, CO2 to carbon.

(Steel) = Annual mass of molten steel charged to the 

vessel (metric tons).

(CSteelin) = Carbon content of the molten steel before 

decarburization, from the carbon analysis results 

(expressed as a decimal fraction).

(CSteelout) = Carbon content of the molten steel after 

decarburization, from the carbon analysis results 

(expressed as a decimal fraction).

(R) = Annual mass of air pollution control residue 

collected (metric tons).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (expressed 

as a decimal fraction).

Clarifies the order of operations in the equation. 
24

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

Q 98.173(b)(1)(

vii)

(Fg) = Annual volume of the gaseous fuel combusted 

(scf).

(Fg) = Annual volume of the gaseous fuel used (scf). Clarifies equation term

Q 98.173(b)(1)(

vii)

(COre) = Carbon content of the iron ore or iron ore 

pellets, from the carbon analysis results (percent by 

weight, expressed as a decimal fraction).

(CCarbon) = Carbon content of the carbonaceous 

materials, from the carbon analysis results (percent 

by weight, expressed as a decimal fraction).

(COther) = Average carbon content of the other 

materials charged to the furnace, from the carbon 

analysis results (percent by weight, expressed as a 

decimal fraction).

(CIron) = Carbon content of the iron, from the carbon 

analysis results (percent by weight, expressed as a 

decimal fraction).

(CNM) = Carbon content of the non-metallic 

materials, from the carbon analysis results (percent 

by weight, expressed as a decimal fraction).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (percent by 

weight, expressed as a decimal fraction).

(COre) = Carbon content of the iron ore or iron ore 

pellets, from the carbon analysis results (expressed 

as a decimal fraction).

(CCarbon) = Carbon content of the carbonaceous 

materials, from the carbon analysis results (expressed 

as a decimal fraction).

(COther) = Average carbon content of the other 

materials charged to the furnace, from the carbon 

analysis results (expressed as a decimal fraction).

(CIron) = Carbon content of the iron, from the carbon 

analysis results (expressed as a decimal fraction).

(CNM) = Carbon content of the non-metallic 

materials, from the carbon analysis results (expressed 

as a decimal fraction).

(CR) = Carbon content of the air pollution control 

residue, from the carbon analysis results (expressed 

as a decimal fraction).

Clarifies equation terms 

Q 98.173(c ) (c) You must determine emissions of CO2 from the 

coke pushing process in mtCO2e by multiplying the 

metric tons of coal charged to the coke ovens during 

the reporting period by 0.008.

(c) You must determine emissions of CO2 from the 

coke pushing process in mtCO2e by multiplying the 

metric tons of coal charged to the by-product 

recovery and non-recovery coke ovens during the 

reporting period by 0.008.

Clarifies requirement.

Q 98.173(d) (d)If GHG emissions from a taconite indurating 

furnace, basic oxygen furnace, non-recovery coke 

oven battery, sinter process, EAF, decarburization 

vessel, or direct reduction furnace are vented through 

the same stack as any combustion unit or process 

equipment that reports CO2 emissions using a CEMS 

that complies with the Tier 4 Calculation 

Methodology in subpart C of this part (General 

Stationary Fuel Combustion Sources), then the 

calculation methodology in paragraph (b) of this 

section shall not be used to calculate process 

emissions. The owner or operator shall report under 

this subpart the combined stack emissions according 

(d)If GHG emissions from a taconite indurating 

furnace, basic oxygen furnace, non-recovery coke 

oven battery, sinter process, EAF, decarburization 

vessel, or direct reduction furnace are vented through 

a stack equipped with a CEMS that complies with 

the Tier 4 methodology in subpart C of this part, or 

through the same stack as any combustion unit or 

process equipment that reports CO2 emissions using 

a CEMS that complies with the Tier 4 Calculation 

Methodology in subpart C of this part (General 

Stationary Fuel Combustion Sources), then the 

calculation methodology in paragraph (b) of this 

section shall not be used to calculate process 

See preamble text for explanation
25

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

to the Tier 4 Calculation Methodology in 

§98.33(a)(4) and all associated requirements for Tier 

4 in subpart C of this part (General Stationary Fuel 

Combustion Sources).

emissions. The owner or operator shall report under 

this subpart the combined stack emissions according 

to the Tier 4 Calculation Methodology in 

§98.33(a)(4) and comply with all associated 

requirements for Tier 4 in subpart C of this part 

(General Stationary Fuel Combustion Sources).

Q 98.174(b)(1) (1) Except as provided in paragraph (b)(4) of this 

section, determine the mass of each process input 

and output other than fuels using the same plant 

instruments or procedures that are used for 

accounting purposes (such as weigh hoppers, belt 

weigh feeders, weighed purchased quantities in 

shipments or containers, combination of bulk density 

and volume measurements, etc.), record the totals for 

each process input and output for each calendar 

month, and sum the monthly mass to determine the 

annual mass for each process input and output. 

Determine the mass rate of fuels using the 

procedures for combustion units in §98.34.

(1) Except as provided in paragraph (b)(4) of this 

section, determine the mass of each process input 

and output other than fuels using the same plant 

instruments or procedures that are used for 

accounting purposes (such as weigh hoppers, belt 

weigh feeders, weighed purchased quantities in 

shipments or containers, combination of bulk density 

and volume measurements, etc.), record the totals for 

each process input and output for each calendar 

month, and sum the monthly mass to determine the 

annual mass for each process input and output. 

Determine the mass rate of fuels using the 

procedures for combustion units in §98.34. No 

determination of the mass of steel output from 

decarburization vessels is required.

See preamble text for explanation

Q 98.174(c )(2) (2)For the furnace exhaust from basic oxygen 

furnaces, EAFs, decarburization vessels, and direct 

reduction furnaces, sample the furnace exhaust for at 

least three complete production cycles that start 

when the furnace is being charged and end after steel 

or iron and slag have been tapped. For EAFs that 

produce both carbon steel and stainless or specialty 

(low carbon) steel, develop an emission factor for the 

production of both types of steel.

(2)(i) For the exhaust from basic oxygen furnaces, 

EAFs, decarburization vessels, and direct reduction 

furnaces, sample the furnace exhaust for at least 

three complete production cycles that start when the 

furnace is being charged and end after steel or iron 

and slag have been tapped. For EAFs that produce 

both carbon steel and stainless or specialty (low 

carbon) steel, develop an emission factor for the 

production of both types of steel.

(ii) For the exhaust from continuously charged 

EAFs, sample the exhaust for a period spanning at 

least three three hours. For EAFs that produce both 

carbon steel and stainless or specialty (low carbon) 

steel, develop an emission factor for the production 

of both types of steel.

See preamble text for explanation

Q 98.175(a) (a) For each missing data for the carbon content of 

inputs and outputs for facilities that estimate 

emissions using the carbon mass balance procedure 

(a) Except as provided in §98.174(b)(4), 100 percent 

data availability is required for the carbon content of 

inputs and outputs for facilities that estimate 

See preamble text for explanation
26

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

in §98.173(b)(1) or for facilities that estimate 

emissions using the site-specific emission factor 

procedure in §98.173(b)(2); 100 percent data 

availability is required. You must repeat the test for 

average carbon contents of inputs and outputs 

according to the procedures in §98.174(b)(2). 

Similarly, you must repeat the test to determine the 

site-specific emission factor if data on the CO2

emission rate, process production rate or process 

feed rate are missing.

emissions using the carbon mass balance procedure 

in §98.173(b)(1) or facilities that estimate emissions 

using the site-specific emission factor procedure in 

§98.173(b)(2). 

Q 98.176(e) (e) If you use the carbon mass balance method in 

§98.173(b)(1) to determine CO2 emissions, you must 

report the following information for each process:

(e) If you use the carbon mass balance method in 

§98.173(b)(1) to determine CO2 emissions, you 

must, except as provided in §98.174(b)(4), report the 

following information for each process:

See preamble text for explanation

Q 98.177(b) (b) When the carbon mass balance method is used to 

estimate emissions for a process, the monthly mass 

of each process input and output that are used to 

determine the annual mass.

(b) When the carbon mass balance method is used to 

estimate emissions for a process, the monthly mass 

of each process input and output that are used to 

determine the annual mass, except that no 

determination of the mass of steel output from 

decarburization vessels is required.

Separate measurements of the mass of liquid steel 

input to the decarburization vessel and decarburized 

liquid steel output from the decarburization vessel 

are not required, because these masses are very 

nearly equal.

S 98.190 (a) (a) Lime manufacturing plants (LMPs) engage in the 

manufacture of a lime product (e.g., calcium oxide, 

high-calcium quicklime, calcium hydroxide, 

hydrated lime, dolomitic quicklime, dolomitic 

hydrate, or other lime products) by calcination of 

limestone, dolomite, shells or other calcareous 

substances as defined in 40 CFR 63.7081(a)(1).

(a) Lime manufacturing plants (LMPs) engage in the 

manufacture of a lime product by calcination of 

limestone, dolomite, shells or other calcareous 

substances as defined in 40 CFR 63.7081(a)(1).

Clarifies the applicability.

S 98.193(a) (a) If all lime kilns meet the conditions specified in 

§98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and 

report under this subpart the combined process and 

combustion CO2 emissions by operating and 

maintaining a CEMS to measure CO2 emissions 

according to the Tier 4 Calculation Methodology 

specified in §98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of this part 

(General Stationary Fuel Combustion Sources).

(a) If all lime kilns meet the conditions specified in 

§98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and 

report under this subpart the combined process and 

combustion CO2 emissions from all lime kilns by 

operating and maintaining a CEMS to measure CO2

emissions according to the Tier 4 Calculation 

Methodology specified in §98.33(a)(4) and all 

associated requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel Combustion 

Sources).

Clarifies language.

S 98.193(b)(1) (1) Calculate and report under this subpart the 

combined process and combustion CO2 emissions by 

(1) Calculate and report under this subpart the 

combined process and combustion CO2 emissions 

Clarifies language.
27

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

operating and maintaining a CEMS to measure CO2

emissions from all lime kilns according to the Tier 4 

Calculation Methodology specified in §98.33(a)(4) 

and all associated requirements for Tier 4 in subpart 

C of this part (General Stationary Fuel Combustion 

Sources).

from all lime kilns by operating and maintaining a 

CEMS to measure CO2 emissions from all lime kilns 

according to the Tier 4 Calculation Methodology 

specified in §98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of this part 

(General Stationary Fuel Combustion Sources).

S 98.193(b)(2) (2) Calculate and report process and combustion CO2

emissions separately using the procedures specified 

in paragraphs (b)(2)(i) through (b)(2)(v) of this 

section.

(2) Calculate and report process and combustion CO2

emissions from all lime kilns separately using the 

procedures specified in paragraphs (b)(2)(i) through 

(b)(2)(v) of this section.

Clarifies language.

S 98.193(b)(2)(

ii)

(ii) You must calculate a monthly emission factor for 

each type of calcined byproduct/waste sold 

(including lime kiln dust) using Equation S–2 of this 

section:

(ii) You must calculate a monthly emission factor for 

each type of calcined byproduct or waste sold 

(including lime kiln dust) using Equation S–2 of this 

section:

Clarifies language.

S 98.193(b)(2)(

ii)

EFLKD,I,N= Emission factor for calcined lime 

byproduct/waste type i sold, for month n (metric tons 

CO2/ton lime product.

EFLKD,I,N= Emission factor for calcined lime 

byproduct or waste type i sold, for month n (metric 

tons CO2/ton lime product.

Clarifies a calculation term. 

S 98.193(b)(2)(

ii)

CaOLKD,i,n= Calcium oxide content for calcined lime 

byproduct/ waste type i sold, for month n (metric 

tons CaO / metric ton lime).

CaOLKD,i,n= Calcium oxide content for calcined lime 

byproduct or waste type i sold, for month n (metric 

tons CaO / metric ton lime).

Clarifies a calculation term. 

S 98.193(b)(2)(

ii)

MgOLKD,i,n= Magnesium oxide content for calcined 

lime byproduct/waste type i sold, for month n (metric 

tons MgO / metric ton lime).

MgOLKD,i,n= Magnesium oxide content for calcined 

lime byproduct or waste type i sold, for month n 

(metric tons MgO / metric ton lime).

Clarifies a calculation term. 

S 98.193(b)(2)(

iii)

(iii) You must calculate the annual CO2 emissions 

from each type of calcined byproduct/waste that is 

not sold (including lime kiln dust and scrubber 

sludge) using Equation S–3 of this section:

(iii) You must calculate the annual CO2 emissions 

from each type of calcined byproduct or waste that is 

not sold (including lime kiln dust and scrubber 

sludge) using Equation S–3 of this section:

Clarifies language.

S 98.193(b)(2)(

iii)

Ewaste,i= Annual CO2 emissions for calcined lime 

byproduct/waste type i that is not sold (metric tons 

CO2)

Ewaste,i= Annual CO2 emissions for calcined lime 

byproduct or waste type i that is not sold (metric tons 

CO2)

Clarifies a calculation term. 

S 98.193(b)(2)(

iii)

CaOwaste,i= Calcium oxide content for calcined lime 

byproduct/ waste type i that is not sold (metric tons 

CaO / metric ton lime).

CaOwaste,i= Calcium oxide content for calcined lime 

byproduct or waste type i that is not sold (metric tons 

CaO / metric ton lime).

Clarifies a calculation term. 

S 98.193(b)(2)(

iii)

MgOWaste,i= Magnesium oxide content for calcined 

lime byproduct/ waste type i that is not sold (metric 

tons MgO / metric ton lime).

MgOWaste,i= Magnesium oxide content for calcined 

lime byproduct or waste type i that is not sold 

(metric tons MgO / metric ton lime).

Clarifies a calculation term. 

S 98.193(b)(2)(

iii)

MWaste,i= Annual weight or mass of calcined 

byproducts/wastes for lime type i that is not sold 

MWaste,i= Annual weight or mass of calcined 

byproducts or wastes for lime type i that is not sold 

Clarifies a calculation term. 
28

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

(tons). (tons).

S 98.193b(2)(iv

)

(iv) You must calculate annual CO2 process 

emissions for all kilns using Equation S–4 of this 

section:

(iv) You must calculate annual CO2 process 

emissions for all lime kilns using Equation S–4 of 

this section:

Clarifies language.

S 98.193b(2)(iv

) 

ECO2 = Annual CO2 process emissions from lime 

production from all kilns (metric tons/year).

ECO2 = Annual CO2 process emissions from lime 

production from all lime kilns (metric tons/year).

Clarifies a calculation term and corrects subscripts. 

S 98.193b(2)(iv

) 

EFLKD,i,n = Emission factor of calcined 

byproducts/wastes sold for lime type i in calendar 

month n, (metric tons CO2/ton byproduct/waste) 

from Equation S–2 of this section.

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.

Clarifies a calculation term. 

S 98.193b(2)(iv

) MLKD,i,n = Monthly weight or mass of calcined 

byproducts/waste sold (such as lime kiln dust, LKD) 

for lime type i in calendar month n (tons).

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).

Clarifies a calculation term. 

S 98.193b(2)(iv

) 

Ewaste,i = Annual CO2 emissions for calcined lime 

byproduct/waste type i that is not sold (metric tons 

CO2) from Equation S–3 of this section.

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.

Clarifies a calculation term. 

S 98.193b(2)(iv

)

b = Number of calcined byproducts/wastes that are 

sold.

b = Number of calcined byproducts or wastes that are 

sold.

Clarifies a calculation term. 

S 98.193b(2)(iv

) 

z = Number of calcined byproducts/wastes that are 

not sold.

z = Number of calcined byproducts or wastes that are 

not sold.

Clarifies a calculation term. 

S 98.194(a) (a) You must determine the total quantity of each 

type of lime product that is produced and each 

calcined byproduct/waste (such as lime kiln dust) 

that is sold. The quantities of each should be directly 

measured monthly with the same plant instruments 

used for accounting purposes, including but not 

limited to, calibrated weigh feeders, rail or truck 

scales, and barge measurements. The direct 

measurements of each lime product shall be 

reconciled annually with the difference in the 

beginning of and end of year inventories for these 

products, when measurements represent lime sold.

(a) You must determine the total quantity of each 

type of lime product that is produced and each 

calcined byproduct or waste (such as lime kiln dust) 

that is sold. The quantities of each should be directly 

measured monthly with the same plant instruments 

used for accounting purposes, including but not 

limited to, calibrated weigh feeders, rail or truck 

scales, and barge measurements. The direct 

measurements of each lime product shall be 

reconciled annually with the difference in the 

beginning of and end of year inventories for these 

products, when measurements represent lime sold.

Clarifies language.

S 98.194(b) (b) You must determine the annual quantity of each 

calcined byproduct/waste generated that is not sold 

by either direct measurement using the same 

(b) You must determine the annual quantity of each 

calcined byproduct or waste generated that is not 

sold by either direct measurement using the same 

Clarifies language.
29

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

instruments identified in paragraph (a) of this section 

or by using a calcined byproduct/waste generation 

rate.

instruments identified in paragraph (a) of this section 

or by using a calcined byproduct or waste generation 

rate.

S 98.194(c) (c) You must determine the chemical composition 

(percent total CaO and percent total MgO) of each 

type of lime product that is produced and each type 

of calcined byproduct/waste sold according to 

paragraph (c)(1) or (2) of this section. You must 

determine the chemical composition of each type of 

lime product that is produced and each type of 

calcined byproduct/waste sold on a monthly basis. 

You must determine the chemical composition for 

each type of calcined byproduct/waste that is not 

sold on an annual basis.

(c) You must determine the chemical composition 

(percent total CaO and percent total MgO) of each 

type of lime product that is produced and each type 

of calcined byproduct or waste sold according to 

paragraph (c)(1) or (2) of this section. You must 

determine the chemical composition of each type of 

lime product that is produced and each type of 

calcined byproduct or waste sold on a monthly basis. 

You must determine the chemical composition for 

each type of calcined byproduct or waste that is not 

sold on an annual basis.

Clarifies language.

S 98.195(a) (a) For each missing value of the quantity of lime 

produced (by lime type), and quantity of calcined 

byproduct/waste produced and sold, the substitute 

data value shall be the best available estimate based 

on all available process data or data used for 

accounting purposes.

(a) For each missing value of the quantity of lime 

produced (by lime type), and quantity of calcined 

byproduct or waste produced and sold, the substitute 

data value shall be the best available estimate based 

on all available process data or data used for 

accounting purposes.

Clarifies language.

S 98.196(a)(1) (1) Method used to determine the quantity of lime 

that is produced and sold.

(1) Method used to determine the quantity of lime 

that is produced and quantity of lime that is sold.

Clarifies language.

S 98.196(a)(2) (2) Method used to determine the quantity of 

calcined lime byproduct/waste sold.

(2) Method used to determine the quantity of 

calcined lime byproduct or waste sold.

Clarifies language.

S 98.196(a)(4) (4) Beginning and end of year inventories for 

calcined lime byproducts/wastes sold, by type.

(4) Beginning and end of year inventories for 

calcined lime byproducts or wastes sold, by type.

Clarifies language.

S 98.196(a)(5) (5) Annual amount of calcined lime byproduct/waste 

sold, by type (tons).

(5) Annual amount of calcined lime byproduct or 

waste sold, by type (tons).

Clarifies language.

S 98.196(a)(7) (7) Annual amount of calcined lime byproduct/waste 

that is not sold, by type (tons).

(7) Annual amount of calcined lime byproduct or 

waste that is not sold, by type (tons).

Clarifies language.

S 98.196(b)(1) (1) Annual CO2 process emissions from all kilns 

combined (metric tons).

(1) Annual CO2 process emissions from all lime 

kilns combined (metric tons).

Clarifies language.

S 98.196(b)(2) (2) Monthly emission factors for each lime type 

produced.

(2) Monthly emission factors (metric ton CO2/ton 

lime product) for each lime product type produced.

Clarifies language.

S 98.196(b)(3) (3) Monthly emission factors for each calcined 

byproduct/waste by lime type that is sold.

(3) Monthly emission factors for each calcined 

byproduct or waste by lime type that is sold.

Clarifies language.

S 98.196(b)(4) (4) Standard method used (ASTM or NLA testing 

method) to determine chemical compositions of each 

(4) Standard method used (ASTM or NLA testing 

method) to determine chemical compositions of each 

Clarifies language.
30

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

lime type produced and each calcined lime 

byproduct/waste type.

lime type produced and each calcined lime byproduct 

or waste type.

S 98.196(b)(5) (5) Monthly results of chemical composition analysis 

of each type of lime product produced and calcined 

byproduct/waste sold.

(5) Monthly results of chemical composition analysis 

of each type of lime product produced and calcined 

byproduct or waste sold.

Clarifies language.

S 98.196(b)(6) (6) Annual results of chemical composition analysis 

of each type of lime byproduct/waste that is not sold.

(6) Annual results of chemical composition analysis 

of each type of lime byproduct or waste that is not 

sold.

Clarifies language.

S 98.196(b)(9) (9) Method used to determine the quantity of 

calcined lime byproduct/waste sold.

(9) Method used to determine the quantity of 

calcined lime byproduct or waste sold.

Clarifies language.

S 98.196(b)(10) (10) Monthly amount of calcined lime 

byproduct/waste sold, by type (tons).

(10) Monthly amount of calcined lime byproduct or 

waste sold, by type (tons).

Clarifies language.

S 98.196(b)(11) (11) Annual amount of calcined lime 

byproduct/waste that is not sold, by type (tons).

(11) Annual amount of calcined lime byproduct or 

waste that is not sold, by type (tons).

Clarifies language.

S 98.196(b)(14) (14) Beginning and end of year inventories for 

calcined lime byproducts/wastes sold.

(14) Beginning and end of year inventories for 

calcined lime byproducts or wastes sold.

Clarifies language.

V 98.222(a) (a) You must report N2O process emissions from 

each nitric acid production train as required by this 

subpart.

(a) You must report N2O process emissions from 

each nitric acid train as required by this subpart.

Clarifies language.

V 98.223(b) (b) You must conduct an annual performance test for 

each nitric acid train according to paragraphs (b)(1) 

through (3) of this section.

(b) You must conduct an annual performance test for 

each nitric acid train according to paragraphs (b)(1) 

through (b)(3) of this section.

Clarifies language.

V 98.223(b)(1) (1) You must conduct the performance test at the 

absorber tail gas vent, referred to as the test point, for 

each nitric acid train according to §98.224(b) 

through (f). If multiple nitric acid production units 

exhaust to a common abatement technology and/or 

emission point, you must sample each process in the 

ducts before the emissions are combined, sample 

each process when only one process is operating, or 

sample the combined emissions when multiple 

processes are operating and base the site-specific 

emission factor on the combined production rate of 

the multiple nitric acid production units.

(1) You must conduct the performance test at the 

absorber tail gas vent, referred to as the test point, for 

each nitric acid train according to §98.224(b)

through (f). If multiple nitric acid trains exhaust to a 

common abatement technology and/or emission 

point, you must sample each process in the ducts 

before the emissions are combined, sample each 

process when only one process is operating, or 

sample the combined emissions when multiple 

processes are operating and base the site-specific 

emission factor on the combined production rate of 

the multiple nitric acid trains.

Clarifies terminology of the production units

V 98.223(b)(3) (3) You must measure the production rate during the 

performance test and calculate the production rate for 

the test period in metric tons (100 percent acid basis) 

(3) You must measure the production rate during the 

performance test and calculate the production rate for 

the test period in tons (100 percent acid basis) per 

Clarifies units of measurement.
31

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

per hour. hour.

V 98.223(d) (d) If nitric acid train ―t‖ exhausts to any N2O

abatement technology ―N‖ after the test point, you 

must determine the destruction efficiency for each 

N2O abatement technology ―N‖ according to 

paragraphs (d)(1), (d)(2), or (d)(3) of this section.

(d) If nitric acid train ―t‖ exhausts to any N2O

abatement technology ―N‖, you must determine the 

destruction efficiency for each N2O abatement 

technology ―N‖ according to paragraphs (d)(1), 

(d)(2), or (d)(3) of this section.

Clarifies requirement.

V 98.223(e) (e) If nitric acid train ―t‖ exhausts to any N2O

abatement technology ―N‖ after the test point, you 

must determine the annual amount of nitric acid 

produced on train ―t‖ while N2O abatement 

technology ―N‖ is operating according to §98.224(f). 

Then you must calculate the abatement utilization 

factor for each N2O abatement technology ―N‖ for 

each nitric acid train ―t‖ according to Equation V–2 

of this section.

(e) If nitric acid train ―t‖ exhausts to any N2O

abatement technology ―N‖, you must determine the 

annual amount of nitric acid produced on nitric acid 

train ―t‖ while N2O abatement technology ―N‖ is 

operating according to §98.224(f). Then you must 

calculate the abatement utilization factor for each 

N2O abatement technology ―N‖ for each nitric acid 

train ―t‖ according to Equation V–2 of this section.

Clarifies requirement

V 98.223(e) Pa,t,N Pt,N Corrects equation term

V 98.223(g)(1) EN2Ot = Annual N2O mass emissions from nitric 

acid production unit ―t‖ according to this Equation 

V–3a (metric tons)

EN2Ot = Annual N2O mass emissions from nitric 

acid train ―t‖ according to this Equation V–3a 

(metric tons).

Clarifies terminology of the production units

V 98.223(g)(1) Pt = Annual nitric acid production from the train ―t‖ 

(ton acid produced, 100 percent acid basis).

Pt = Annual nitric acid production from nitric acid 

train ―t‖ (ton acid produced, 100 percent acid basis).

Clarifies an equation term.

V 98.223(g)(1) DF = Destruction efficiency of N2O abatement 

technology N that is used on nitric acid train ―t‖ 

(percent of N2O removed from vent stream).

DF = Destruction efficiency of N2O abatement 

technology N that is used on nitric acid train ―t‖ 

(decimal fraction of N2O removed from vent stream).

Corrects a calculation term.

V 98.223(g)(1) AF = Abatement utilization factor of N2O abatement 

technology ―N‖ for nitric acid train ―t‖ (percent of 

time that the abatement technology is operating).

AF = Abatement utilization factor of N2O abatement 

technology ―N‖ for nitric acid train ―t‖ (decimal 

fraction of annual production during which 

abatement technology is operating).

Clarifies an equation term.

V 98.223(g)(2) (2) If multiple N2O abatement technologies are 

located in series after your test point, you must use 

the emissions factor (determined in Equation V–1 of 

this section), the destruction efficiency (determined 

in paragraph (d) of this section), the annual nitric 

acid production (determined in paragraph (f) of this 

section), and the abatement utilization factor 

(determined in paragraph (e) of this section), 

according to Equation V–3b of this section:

(2) If multiple N2O abatement technologies are 

located in series after your test point, you must use 

the emissions factor (determined in Equation V–1 of 

this section), the destruction efficiency (determined 

in paragraph (d) of this section), the annual nitric 

acid production (determined in paragraph (i) of this 

section), and the abatement utilization factor 

(determined in paragraph (e) of this section), 

according to Equation V–3b of this section:

Corrects a paragraph reference

V 98.223(g)(2) EN2Ot = Annual N2O mass emissions from nitric acid EN2Ot = Annual N2O mass emissions from nitric acid Clarifies terminology of the production units
32

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

production unit ―t‖ according to this Equation V–3b 

(metric tons).

train ―t‖ according to this Equation V–3b (metric 

tons).

V 98.223(g)(2) EFN2O,t = N2O emissions factor for unit ―t‖ (lb 

N2O/ton nitric acid produced).

EFN2O,t = N2O emissions factor for nitric acid train 

―t‖ (lb N2O/ton nitric acid produced).

Clarifies terminology of the production units

V 98.223(g)(2) Pt = Annual nitric acid produced from unit ―t‖ (ton 

acid produced, 100 percent acid basis).

Pt = Annual nitric acid produced from nitric acid 

train ―t‖ (ton acid produced, 100 percent acid basis).

Clarifies terminology of the production units

V 98.223(g)(2) DF1 = Destruction efficiency of N2O abatement 

technology 1 (percent of N2O removed from vent 

stream).

DF1 = Destruction efficiency of N2O abatement 

technology 1 (decimal fraction of N2O removed from 

vent stream).

Corrects a calculation term.

V 98.223(g)(2) AF1 = Abatement utilization factor of N2O abatement 

technology 1 (percent of time that abatement 

technology 1 is operating).

AF1 = Abatement utilization factor of N2O abatement 

technology 1 (decimal fraction of time that 

abatement technology 1 is operating).

Corrects a calculation term.

V 98.223(g)(2) DF2 = Destruction efficiency of N2O abatement 

technology 2 (percent of N2O removed from vent 

stream).

DF2 = Destruction efficiency of N2O abatement 

technology 2 (decimal fraction of N2O removed from 

vent stream).

Corrects a calculation term.

V 98.223(g)(2) AF2 = Abatement utilization factor of N2O abatement 

technology 2 (percent of time that abatement 

technology 2 is operating).

AF2 = Abatement utilization factor of N2O abatement 

technology 2 (decimal fraction of time that 

abatement technology 2 is operating).

Corrects a calculation term.

V 98.223(g)(2) DFN = Destruction efficiency of N2O abatement 

technology N (percent of N2O removed from vent 

stream).

DFN = Destruction efficiency of N2O abatement 

technology N (decimal fraction of N2O removed 

from vent stream).

Corrects a calculation term.

V 98.223(g)(2) AFN = Abatement utilization factor of N2O

abatement technology N (percent of time that 

abatement technology N is operating).

AFN = Abatement utilization factor of N2O

abatement technology N (decimal fraction of time 

that abatement technology N is operating).

Corrects a calculation term.

V 98.223(g)(3) (3) If multiple N2O abatement technologies are 

located in parallel after your test point, you must use 

the emissions factor (determined in Equation V–1 of 

this section), the destruction efficiency (determined 

in paragraph (d) of this section), the annual nitric 

acid production (determined in paragraph (f) of this 

section), and the abatement utilization factor 

(determined in paragraph (e) of this section), 

according to Equation V–3c of this section:

(3) If multiple N2O abatement technologies are

located in parallel after your test point, you must use 

the emissions factor (determined in Equation V–1 of 

this section), the destruction efficiency (determined 

in paragraph (d) of this section), the annual nitric 

acid production (determined in paragraph (i) of this 

section), and the abatement utilization factor 

(determined in paragraph (e) of this section), 

according to Equation V–3c of this section:

Corrects a paragraph reference

V 98.223(g)(3) EN2Ot = Annual N2O mass emissions from nitric acid 

production unit ―t‖ according to this Equation V–3c 

(metric tons).

EN2Ot = Annual N2O mass emissions from nitric acid 

train ―t‖ according to this Equation V–3c (metric 

tons).

Clarifies terminology of the production units

V 98.223(g)(3) EFN2O,t = N2O emissions factor for unit ―t‖ (lb 

N2O/ton nitric acid produced).

EFN2O,t = N2O emissions factor for nitric acid train 

―t‖ (lb N2O/ton nitric acid produced).

Clarifies terminology of the production units
33

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

V 98.223(g)(3) Pt = Annual nitric acid produced from unit ―t‖ (ton 

acid produced, 100 percent acid basis).

Pt = Annual nitric acid produced from nitric acid 

train ―t‖ (ton acid produced, 100 percent acid basis).

Clarifies terminology of the production units

V 98.223(g)(3) DFN = Destruction efficiency of N2O abatement 

technology ―N‖ (percent of N2O removed from vent 

stream).

DFN = Destruction efficiency of N2O abatement 

technology ―N‖ (decimal fraction of N2O removed 

from vent stream).

Corrects a calculation term.

V 98.223(g)(3) AFN = Abatement utilization factor of N2O

abatement technology ―N‖ (percent of time that 

abatement technology ―N‖ is operating).

AFN = Abatement utilization factor of N2O

abatement technology ―N‖ (decimal fraction of time 

that abatement technology ―N‖ is operating).

Corrects a calculation term.

V 98.223(g)(3) FCN = Fraction control factor of N2O abatement 

technology ―N‖ (percent of total emissions from unit 

―t‖ that are sent to abatement technology ―N‖).

FCN = Fraction control factor of N2O abatement 

technology ―N‖ (decimal fraction of total emissions 

from nitric acid train ―t‖ that are sent to abatement 

technology ―N‖).

Corrects a calculation term.

V 98.223(g)(4) EN2Ot = Annual N2O mass emissions from nitric acid 

production unit ―t‖ according to this Equation V–3d 

(metric tons).

EN2Ot = Annual N2O mass emissions from nitric acid 

train ―t‖ according to this Equation V–3d (metric 

tons).

Corrects a calculation term.

V 98.223(i) (i) You must determine the total annual amount of 

nitric acid produced on nitric acid train ―t‖ for each 

nitric acid train (tons acid produced, 100 percent acid 

basis), according to §98.224(f).

(i) You must determine the total annual amount of 

nitric acid produced on each nitric acid train ―t‖ (tons 

acid produced, 100 percent acid basis), according to 

§98.224(f).

Clarifies terminology of the production units

V 98.224(c) (c) You must determine the production rate(s) (100 

percent basis) from each nitric acid train during the 

performance test according to paragraphs (c)(1) or 

(c)(2) of this section.

(c) You must determine the production rate(s) (100 

percent acid basis) from each nitric acid train during 

the performance test according to paragraphs (c)(1) 

or (c)(2) of this section.

Clarifies units for a calculation term.

V 98.224(e) (e) You must determine the total monthly amount of 

nitric acid produced. You must also determine the 

monthly amount of nitric acid produced while N2O

abatement technology (located after the test point) is 

operating from each nitric acid train. These monthly 

amounts are determined according to the methods in 

paragraphs (c)(1) or (2) of this section.

(e) You must determine the total monthly amount of 

nitric acid produced. You must also determine the 

monthly amount of nitric acid produced while N2O

abatement technology is operating from each nitric 

acid train. These monthly amounts are determined 

according to the methods in paragraphs (c)(1) or (2) 

of this section.

Clarifies requirements.

V 98.224(f) (f) You must determine the annual amount of nitric 

acid produced. You must also determine the annual 

amount of nitric acid produced while N2O abatement 

technology (located after the test point) is operating 

for each train. These annual amounts are determined 

by summing the respective monthly nitric acid 

quantities determined in paragraph (e) of this section.

(f) You must determine the annual amount of nitric 

acid produced. You must also determine the annual 

amount of nitric acid produced while N2O abatement 

technology is operating for each nitric acid train. 

These annual amounts are determined by summing 

the respective monthly nitric acid quantities 

determined in paragraph (e) of this section.

Clarifies requirements.

V 98.226(a) (a) Train identification number. (a) Nitric Acid train identification number. Clarifies requirements.
34

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

V 98.226(n) (n) If you requested Administrator approval for an 

alternative method of determining N2O emissions 

under §98.223(a)(2), each annual report must also 

contain the information specified in paragraphs 

(n)(1) through (4) of this section. (n)(1) through 

(n)(4) of this section for each nitric acid production 

facility.

(n) If you requested Administrator approval for an 

alternative method of determining N2O emissions 

under §98.223(a)(2), each annual report must also 

contain the information specified in paragraphs 

(n)(1) through (n)(4) of this section for each nitric 

acid production facility.

Corrects typographical error

V 98.226(o) (None) (o) [Reserved] Corrects typographical error

V 98.226(p) (p) Fraction control factor for each abatement 

technology (percent of total emissions from the 

production unit that are sent to the abatement 

technology) if equation V–3c is used.

(p) Fraction control factor for each abatement 

technology (percent of total emissions from the nitric 

acid train that are sent to each abatement technology) 

if Equation V–3c is used.

Clarifies terminology of the production units

X 98.242(b)(2) (2) If you comply with §98.243(c), report CO2, CH4, 

and N2O combustion emissions under subpart C of 

this part (General Stationary Fuel Combustion 

Sources) by following the requirements of subpart C 

only for the combustion of supplemental fuel. 

Determine the applicable Tier in subpart C of this 

part (General Stationary Fuel Combustion Sources) 

based on the maximum rated heat input capacity of 

the stationary combustion source.

(2) If you comply with §98.243(c), report CO2, CH4, 

and N2O combustion emissions under subpart C of 

this part (General Stationary Fuel Combustion 

Sources) by following the requirements of subpart 

Cfor all fuels, except emissions from burning 

petrochemical process off-gas in any combustion 

unit are not to be reported under subpart C of this 

part. Determine the applicable Tier in subpart C of 

this part (General Stationary Fuel Combustion 

Sources) based on the maximum rated heat input 

capacity of the stationary combustion source.

See preamble text for explanation

X 98.243(b) (b) Continuous emission monitoring system 

(CEMS). Route all process vent emissions and 

emissions from combustion of process off-gas to one 

or more stacks and determine CO2 emissions from 

each stack (except flare stacks) according to the Tier 

4 Calculation Methodology requirements in subpart 

C of this part. For each stack (except flare stacks) 

that includes emissions from combustion of 

petrochemical process off-gas, calculate CH4 and 

N20 emissions in accordance with subpart C of this 

part (use the Tier 3 methodology, emission factors 

for ―Petroleum‖ in Table C–2 of subpart C of this 

part, and either the default high heat value for fuel 

gas in Table C–1 of subpart C of this part or a 

calculated HHV, as allowed in Equation C–8 of 

subpart C of this part). For each flare, calculate CO2, 

(b) Continuous emission monitoring system 

(CEMS). Route all process vent emissions and 

emissions from stationary combustion units that burn 

any amount of process off-gas to one or more stacks 

and determine GHG emissions as specified in 

paragraphs (b)(1) through (3) of this section.

(1)Determine CO2 emissions from each stack (except 

flare stacks) according to the Tier 4 Calculation 

Methodology requirements in subpart C of this part. 

(2)For each stack (except flare stacks) that includes 

emissions from combustion of petrochemical process 

off-gas, calculate CH4 and N2O emissions in 

accordance with subpart C of this part (use Equation 

C-10 and the "fuel gas" emission factors in Table C–

2 of subpart C of this part).

(3)For each flare, calculate CO2, CH4, and N2O

See preamble text for explanation
35

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

CH4, and N2O emissions using the methodology 

specified in §98.253(b)(1) through (b)(3).

emissions using the methodology specified in 

§98.253(b)(1) through (b)(3).

X 98.243(c)(3) (3) Collect a sample of each feedstock and product at 

least once per month and determine the carbon 

content of each sample according to the procedures 

of §98.244(b)(4). If multiple valid carbon content 

measurements are made during the monthly 

measurement period, average them arithmetically. 

However, if a particular liquid or solid feedstock is 

delivered in lots, and if multiple deliveries of the 

same feedstock are received from the same supply 

source in a given calendar month, only one 

representative sample is required. Alternatively, you 

may use the results of analyses conducted by a fuel 

or feedstock supplier, provided the sampling and 

analysis is conducted at least once per month using 

any of the procedures specified in §98.244(b)(4).

(3) Collect a sample of each feedstock and product at 

least once per month and determine the carbon 

content of each sample according to the procedures 

of §98.244(b)(4). If multiple valid carbon content 

measurements are made during the monthly 

measurement period, average them arithmetically. 

However, if a particular liquid or solid feedstock is 

delivered in lots, and if multiple deliveries of the 

same feedstock are received from the same supply 

source in a given calendar month, only one 

representative sample is required. Alternatively, you 

may use the results of analyses conducted by a 

feedstock supplier, or product customer, provided the 

sampling and analysis is conducted at least once per 

month using any of the procedures specified in 

§98.244(b)(4).

See preamble text for explanation

X 98.243(c)(4) (4) If you determine that the monthly average 

concentration of a specific compound in a feedstock 

or product is greater than 99.5 percent by volume (or 

mass for liquids and solids), then as an alternative to 

the sampling and analysis specified in paragraph 

(c)(3) of this section, you may calculate the carbon 

content assuming 100 percent of that feedstock or 

product is the specific compound during periods of 

normal operation. This alternative may not be used 

for products during periods of operation when offspecification product is produced. You must 

maintain records of any determination made in 

accordance with this paragraph (c)(4) along with all 

supporting data, calculations, and other information. 

You must reevaluate determinations made under this 

paragraph (c)(4) after any process change that affects 

the feedstock or product composition. You must 

keep records of the process change and the 

corresponding composition determinations. If the 

feedstock or product composition changes so that the 

average monthly concentration falls below 99.5 

(4) If you determine that the monthly average 

concentration of a specific compound in a feedstock 

or product is greater than 99.5 percent by volume or 

mass, then as an alternative to the sampling and 

analysis specified in paragraph (c)(3) of this section, 

you may determine carbon content in accordance 

with paragraphs (c)(4)(i) through (iii) of this section.

(i) Calculate the carbon content assuming 100 

percent of that feedstock or product is the specific 

compound. 

(ii) You must maintain records of any determination 

made in accordance with this paragraph (c)(4) along 

with all supporting data, calculations, and other 

information. 

(iii) Reevaluate determinations made under this 

paragraph (c)(4) after any process change that affects 

the feedstock or product composition. Keep records 

of the process change and the corresponding 

composition determinations. If the feedstock or 

product composition changes so that the average 

monthly concentration falls below 99.5 percent, you 

See preamble text for explanation
36

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

percent, you are no longer permitted to use this 

alternative method.

are no longer permitted to use this alternative 

method.

X 98.243(c)(5)(i

)

Cg = Annual net contribution to calculated emissions 

from carbon (C ) in gaseous materials 

(kilograms/year, kg/yr)

(Fgf)i,n = Volume of gaseous feedstock i introduced in 

month "n" (standard cubic feet, scf ). 

(MWf)i = Molecular weight of gaseous feedstock i 

(kg/kg-mole).

(Pgp)i,n = volume of gaseous product i produced in 

month "n" (scf). 

(MWp)i,n = Molecular wieght of gaseous product i 

(kg/kg-mole). 

Cg = Annual net contribution to calculated emissions 

from carbon (C ) in gaseous materials, including 

streams containing CO2 recovered for sale or use in 

another process( kg/yr)

(Fgf) = Volume or mass of gaseous feedstock i 

introduced in month "n" (scf or kg). If you measure 

mass, the term (MWf)i/MVC is replaced with "1". 

(MWf)i,n = Molecular weight of gaseous feedstock i 

in month "n" (kg/kg-mole).

(Pgp)i,n = Volume or mass of gaseous product i 

produced in month "n" (scf or kg). If you measure 

mass, the term (MWp)i/MVC is replaced with "1". 

(MWp)i,n = Molecular wieght of gaseous product i in 

month "n" (kg/kg-mole). 

See preamble text for explanation

X 98.243(d)(3)(

i)

(i) For all gaseous fuels that contain ethylene process 

off-gas, use the emission factors for "Petroleum" in 

Table C–2 of subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(i) For all gaseous fuels that contain ethylene process 

off-gas, use the emission factors for "Fuel Gas" in 

Table C–2 of subpart C of this part (General 

Stationary Fuel Combustion Sources). 

See preamble text for explanation

X 98.244(b)(4) (4) ...Analyses conducted in accordance with 

methods specified in paragraphs (b)(4)(i) through 

(b)(4)(xv) of this section may be performed by the 

owner or operator, by an independent laboratory, or 

by the supplier of a feedstock.

(4) ...Analyses conducted in accordance with 

methods specified in paragraphs (b)(4)(i) through 

(b)(4)(xv) of this section may be performed by the 

owner or operator, by an independent laboratory, by 

the supplier of a feedstock, or by a product customer.

Harmonizing change with 40 CFR 98.243(c)(3).

X 98.244(b)(4)(

xiii)

(xiii) The results of chromatographic analysis of a 

feedstock or product, provided that the gas 

chromatograph is operated, maintained, and 

calibrated according to the manufacturer's 

instructions.

(xiii) The results of chromatographic analysis of a 

feedstock or product, provided that the 

chromatograph is operated, maintained, and 

calibrated according to the manufacturer's 

instructions.

See preamble text for explanation

X 98.244(b)(4)(

xiv)

(xiv) The carbon content results of mass 

spectrometer analysis of a feedstock or product, 

provided that the mass spectrometer is operated, 

maintained, and calibrated according to the 

manufacturer's instructions.

(xiv) The results of mass spectrometer analysis of a 

feedstock or product, provided that the mass 

spectrometer is operated, maintained, and calibrated 

according to the manufacturer's instructions.

See preamble text for explanation

X 98.244(b)(4)(

xv)(A)

(A) An industry standard practice for carbon black 

feedstock oils and carbon black products.

(A) An industry standard practice, or a method 

published by a consensus-based standards 

organization if such a method exists, for carbon 

black feedstock oils and carbon black products. 

See preamble text for explanation
37

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

Consensus-based standards organizations include, 

but are not limited to, the following: ASTM 

International (100 Barr Harbor Drive, P.O. Box 

CB700, West Conshohocken, Pennsylvania 19428-

B2959, (800) 262-1373, http://www.astm.org), the 

American National Standards Institute (ANSI, 1819 

L Street, NW., 6th floor, Washington, DC 20036, 

(202) 293-8020, http://www.ansi.org ), the American 

Gas Association (AGA, 400 North Capitol Street, 

NW., 4th Floor, Washington, DC 20001, (202) 824-

7000, http://www.aga.org ), the American Society of 

Mechanical Engineers (ASME, Three Park Avenue, 

New York, NY 10016-5990, (800) 843-2763, 

http://www.asme.org ), the American Petroleum 

Institute (API, 1220 L Street, NW., Washington, DC 

20005-4070, (202) 682-8000, http://www.api.org ), 

and the North American Energy Standards Board 

(NAESB, 801 Travis Street, Suite 1675, Houston, 

TX 77002, (713) 356-0060, http://www.naesb.org). 

The method(s) used shall be documented in the 

Monitoring Plan required under § 98.3(g)(5).

X 98.244(c) (None) (c) If you comply with §98.243(b) or (d), conduct 

monitoring and QA/QC for flares in accordance with 

§98.254.

See preamble text for explanation

X 98.245

Introductory 

paragraph

For missing feedstock flow rates, product flow rates, 

and carbon contents, use the same procedures as for 

missing flow rates and carbon contents for fuels as 

specified in §98.35.

For missing feedstock and product flow rates, use 

the same procedures as for missing fuel usage as 

specified in §98.35(b)(2). For missing feedstock and 

product carbon contents and missing molecular 

weights for gaseous feedstocks and products, use the 

same procedures as for missing carbon contents and 

missing molecular weights for fuels as specified in 

§98.35(b)(1). For missing flare data, follow the 

procedures in §98.255(b) and (c). 

See preamble text for explanation

X 98.246(a)(6) (6) Name of each method listed in §98.244 used to 

determine a measured parameter (or description of 

manufacturer's recommended method).

(6) For each feedstock and product, provide the 

information specified in paragraphs (a)(6)(i) through 

(a)(6)(iii) of this section.

(i) Name of each method used to determine carbon 

content or molecular weight in accordance with 

98.244(b)(4);

See preamble text for explanation
38

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

(ii) Description of each type of device (e.g., flow 

meter, weighing device) used to determine flow or 

mass in accordance 98.244(b)(1) through (3).

(iii) Identification of each method (i.e., method 

number, title, or other description) used to determine 

flow or mass in accordance with 98.244(b)(1) 

through (3).

X 98.246(a)(8) (8) Identification of each combustion unit that 

burned both process off-gas and supplemental fuel.

(8) Identification of each combustion unit that 

burned both process off-gas and supplemental fuel, 

including combustion units that are not part of the 

petrochemical process unit.

See preamble text for explanation

X 98.246(a)(9) (9) If you comply with the alternative to sampling 

and analysis specified in §98.243(c)(4), the amount 

of time during which off-specification product was 

produced, the volume or mass of off-specification 

product produced, and if applicable, the date of any 

process change that reduced the composition to less 

than 99.5 percent.

(9) If you comply with the alternative to sampling 

and analysis specified in §98.243(c)(4), the number 

of days during which off-specification product was 

produced, and if applicable, the date of any process 

change that reduced the composition to less than 99.5 

percent.

See preamble text for explanation

X 98.246(a)(11) (11) If you determine carbon content or composition 

of a feedstock or product using a method under 

§98.244(b)(4)(xv)(B), report the information listed in 

paragraphs (a)(11)(i) through (a)(11)(iv) of this 

section.

(11) If you determine carbon content or composition 

of a feedstock or product using a method under 

§98.244(b)(4)(xv)(B), report the information listed in 

paragraphs (a)(11)(i) through (a)(11)(iii) of this 

section.

Corrects cross-reference.

X 98.246(b)(2) (2) For CEMS used on stacks for stationary 

combustion units, report the relevant information 

required under §98.36 for the Tier 4 calculation 

methodology. Section 98.36(b)(9)(iii) does not apply 

for the purposes of this subpart.

(2) For CEMS used on stacks that include emissions 

from stationary combustion units that burn any 

amount of off-gas from the petrochemical process, 

report the relevant information required under 

§98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculation 

methodology. Sections §98.36(c)(2)( ii) and 

(c)(2)(ix) do not apply for the purposes of this 

subpart.

Clarifies CEMS reporting requirement to align more 

closely with procedures in e-GGRT and corrects 

cross-reference.

X 98.246(b)(3) (3) For CEMS used on stacks that are not used for 

stationary combustion units, report the information 

required under §98.36(e)(2)(vi).

(3) For CEMS used on stacks that do not include 

emissions from stationary combustion units, report 

the information required under §98.36(b)(6), (b)(7), 

and §98.36(e)(2)(vi).

Clarifies CEMS reporting requirement to align more 

closely with procedures in e-GGRT.
39

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

X 98.246(b)(4) (4) The CO2 emissions from each stack and the 

combined CO2 emissions from all stacks (except 

flare stacks) that handle process vent emissions and 

emissions from stationary combustion units that burn 

process off-gas for the petrochemical process unit. 

For each stationary combustion unit (or group of 

combustion units monitored with a single CO2

CEMS) that burns petrochemical process off-gas, 

provide an estimate based on engineering judgment 

of the fraction of the total emissions that is 

attributable to combustion of off-gas from the 

petrochemical process unit.

(4) For each CEMS monitoring location that meets 

the conditions in paragraph (b)(2) or (3) of this 

section, provide an estimate based on engineering 

judgment of the fraction of the total CO2 emissions 

that is attributable to the petrochemical process unit.

See preamble text for explanation

X 98.246(b)(5) (5) For stationary combustion units that burn process 

off-gas from the petrochemical process unit, report 

the information related to CH4 and N2O emissions as 

specified in paragraphs (b)(5)(i) through (b)(5)(iv) of 

this section.

(i) The CH4 and N2O emissions from each stack that 

is monitored with a CO2 CEMS, expressed in metric 

tons of each gas and in metric tons of CO2 e. For 

each stack provide an estimate based on engineering 

judgment of the fraction of the total emissions that is 

attributable to combustion of off-gas from the 

petrochemical process unit.

(ii) The combined CH4 and N2O emissions from all 

stationary combustion units, expressed in metric tons 

of each gas and in metric tons of CO2 e.

(iii) The quantity of each type of fuel used in 

Equation C–8 in §98.33(c) for each stationary 

combustion unit or group of units (as applicable) 

during the reporting year, expressed in short tons for 

solid fuels, gallons for liquid fuels, and scf for 

gaseous fuels.

(iv) The HHV (either default or annual average from 

(5) For each CEMS monitoring location that meets 

the conditions in paragraph (b)(2) of this section, 

report the CH4 and N2O emissions expressed in 

metric tons of each gas. For each CEMS monitoring 

location, provide an estimate based on engineering 

judgment of the fraction of the total CH4 and N2O

emissions that is attributable to combustion of offgas from the petrochemical process unit.

(i)[Reserved]

(ii)[Reserved]

(iii)[Reserved]

(iv)[Reserved]

See preamble text for explanation
40

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

measured data) used in Equation C–8 in §98.33(c) 

for each stationary combustion unit or group of 

combustion units (as applicable).

X 98.246(b)(6) (6) ID or other appropriate descriptor of each 

stationary combustion unit that burns process offgas.

(6) [Reserved] See preamble text for explanation

X 98.246(c)(4) (4) Name and annual quantity of each feedstock (4) Name and annual quantity of each feedstock 

(metric tons).

Clarifies units of measure for reporting requirement

X 98.247(b) (b) If you comply with the mass balance 

methodology in §98.243(c), then you must retain 

records of the information listed in paragraphs (b)(1) 

through (b)(3) of this section.

(1) Results of feedstock or product composition 

determinations conducted in accordance with 

§98.243(c)(4).

(2) Start and end times and calculated carbon 

contents for time periods when off-specification 

product is produced, if you comply with the 

alternative methodology in §98.243(c)(4) for 

determining carbon content of feedstock or product.

(b) If you comply with the mass balance 

methodology in §98.243(c), then you must retain 

records of the information listed in paragraphs (b)(1) 

through (b)(4) of this section.

(1) Results of feedstock or product composition 

determinations conducted in accordance with 

§98.243(c)(4).

(2) Start and end times for time periods when offspecification product is produced, if you comply 

with the alternative methodology in §98.243(c)(4) 

for determining carbon content of product.

Corrects a reference and reduces recordkeeping 

requirements when the alternative methodology in 

98.234 (c )(4) is used. 

X 98.248 Product, as used in §98.243, means each of the 

following carbon-containing outputs from a process: 

the petrochemical, recovered byproducts, and liquid 

organic wastes that are not incinerated onsite. 

Product does not include process vent emissions, 

fugitive emissions, or wastewater.

Product, as used in §98.243, means each of the 

following carbon-containing outputs from a process: 

the petrochemical, recovered byproducts, and liquid 

organic wastes that are not combusted onsite. 

Product does not include process vent emissions, 

fugitive emissions, or wastewater.

The definition of product has been revised to provide 

consistency with other subparts of this rule. 

Y 98.252(a) (a) .... For CH4 and N2O emissions from combustion 

of fuel gas, use the applicable procedures in 98.33 (c 

) for the same tier methodology that was used for 

calculating CO2 emissions. (Use the default CH4 and 

N2O emission factors for "Petroleum (All fuel types 

in Table C-1)" in Table C-2 of this part. For Tier 3...

(a) .... For CH4 and N2O emissions from combustion 

of fuel gas, use the applicable procedures in 98.33(c ) 

for the same tier methodology that was used for 

calculating CO2 emissions. (Use the default CH4 and 

N2O emission factors for "Fuel Gas" in Table C-2 of 

this part. For Tier 3....

See preamble text for explanation

Y 98.252(i) (i) CO2 emissions from non-merchant hydrogen 

production process units (not including hydrogen 

produced from catalytic reforming units) under this 

subpart. You must follow the calculation 

methodologies, monitoring and QA/QC methods, 

missing data procedures, reporting requirements, and 

recordkeeping requirements of subpart P of this part.

(i) CO2 emissions from non-merchant hydrogen 

production process units (not including hydrogen 

produced from catalytic reforming units) following 

the calculation methodologies, monitoring and 

QA/QC methods, missing data procedures, reporting 

requirements, and recordkeeping requirements of 

subpart P of this part.

Clarifies requirement
41

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

Y 98.253(b)(2) EmFCH4 = Default CH4 emission factor for 

"PetroleumProducts" from Table C-2 of Subpart C of 

this part (General Staionary Fuel Combusion 

Sources) (kg CH4/ MMBtu)

EmFCH4 = Default CH4 emission factor for "Fuel 

Gas" from Table C-2 of Subpart C of this part 

(General Staionary Fuel Combusion Sources) (kg 

CH4/ MMBtu)

See preamble text for explanation

Y 98.253(b)(3) EmFN2O = Default N2O emission factor for 

"PetroleumProducts" from Table C-2 of subpart C of 

this part (General Stationary Fuel Combustion 

Sources) (kg N2O/MMBtu).

EmFN2O = Default N2O emission factor for "Fuel 

Gas" from Table C-2 of subpart C of this part 

(General Stationary Fuel Combustion Sources) (kg 

N2O/MMBtu).

See preamble text for explanation

Y 98.253(f)(2) (2) Flow measurement. If you have a continuous 

flow monitor on the sour gas feed to the sulfur 

recovery plant, you must use the measured flow rates 

when the monitor is operational to calculate the sour 

gas flow rate. If you do not have a continuous flow 

monitor on the sour gas feed to the sulfur recovery 

plant, you must use engineering calculations, 

company records, or similar estimates of volumetric 

sour gas flow.

(2) Flow measurement. If you have a continuous 

flow monitor on the sour gas feed to the sulfur 

recovery plant or the sour gas feed sent for off-site 

sulfur recovery, you must use the measured flow 

rates when the monitor is operational to calculate the 

sour gas flow rate. If you do not have a continuous 

flow monitor on the sour gas feed to the sulfur 

recovery plant or the sour gas feed sent for off-site 

sulfur recovery, you must use engineering 

calculations, company records, or similar estimates 

of volumetric sour gas flow.

Clarifies requirement

Y 98.253(f)(3) (3) Carbon content. If you have a continuous gas 

composition monitor capable of measuring carbon 

content on the sour gas feed to the sulfur recovery 

plant or if you monitor gas composition for carbon 

content on a routine basis, you must use the 

measured carbon content value. Alternatively, you 

may develop a site-specific carbon content factor 

using limited measurement data or engineering 

estimates or use the default factor of 0.20.

(3) Carbon content. If you have a continuous gas 

composition monitor capable of measuring carbon 

content on the sour gas feed to the sulfur recovery 

plant or the sour gas feed sent for off-site for sulfur 

recovery, or if you monitor gas composition for 

carbon content on a routine basis, you must use the 

measured carbon content value. Alternatively, you 

may develop a site-specific carbon content factor 

using limited measurement data or engineering 

estimates or use the default factor of 0.20.

Clarifies requirement

Y 98.253(f)(4) (4) Calculate the CO2 emissions from each sulfur 

recovery plant using Equation Y–12 of this section.

Where:

FSG = Volumetric flow rate of sour gas feed 

(including sour water stripper gas) to the sulfur 

recovery plant (scf/year).

MFC = Mole fraction of carbon in the sour gas to the 

sulfur recovery plant (kg-mole C/kg-mole gas); 

default = 0.20.

(4) Calculate the CO2 emissions from each on-site 

sulfur recovery plant and for sour gas sent off-site for 

sulfur recovery using Equation Y–12 of this section.

Where:

FSG = Volumetric flow rate of sour gas (including 

sour water stripper gas)fed to the sulfur recovery 

plant or the sour gas feed sent for off-site for sulfur 

recovery (scf/year).

MFC = Mole fraction of carbon in the sour gas fed to 

the sulfur recovery plant or the sour gas feed sent for 

See preamble text for explanation
42

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

off-site for sulfur recovery (kg-mole C/kg-mole gas); 

default = 0.20.

Y 98.253(j) (j) For each process vent not covered in paragraphs 

(a) through (i) of this section that can reasonably be 

expected to contain greater than 2 percent by volume 

CO2 or greater than 0.5 percent by volume of CH4 or 

greater than 0.01 percent by volume (100 parts per 

million) of N2O, calculate GHG emissions using the 

Equation Y–19 of this section. You must use 

Equation Y–19 of this section to calculate CH4

emissions for catalytic reforming unit 

depressurization and purge vents when methane is 

used as the purge gas or if you elected this method as 

an alternative to the methods in paragraphs (f), (h), 

or (k) of this section.

(j) For each process vent not covered in paragraphs 

(a) through (i) of this section that can reasonably be 

expected to contain greater than 2 percent by volume 

CO2 or greater than 0.5 percent by volume of CH4 or 

greater than 0.01 percent by volume (100 parts per 

million) of N2O, calculate GHG emissions using the 

Equation Y–19 of this section. You must also use 

Equation Y–19 of this section to calculate CH4

emissions for catalytic reforming unit 

depressurization and purge vents when methane is 

used as the purge gas, CH4 emissions if you elected 

to use the method in (i)(1) of this section, and CO2

and/or CH4 emissions, as applicable, if you elected 

this method as an alternative to the methods in 

paragraphs (f), (h), or (k) of this section.

See preamble text for explanation

Y 98.253(k) (k) For uncontrolled blowdown systems, you must 

calculate CH4 emissions either using the methods for 

process vents in paragraph (j) of this section 

regardless of the CH4concentration or using Equation 

Y20 of this section. Blowdown systems where the 

uncondensed gas stream is routed to a flare or similar 

control device is considered to be controlled and is 

not required to estimate emissions under this 

paragraph (k).

(k) For uncontrolled blowdown systems, you must 

calculate CH4 emissions either using the methods for 

process vents in paragraph (j) of this section 

regardless of the CH4concentration or using Equation 

Y-20 of this section. Blowdown systems where the 

uncondensed gas stream is routed to a flare or similar 

control device is considered to be controlled and is 

not required to estimate emissions under this 

paragraph (k).

Corrects typographical error in reference to equation 

Y-20

Y 98.253(m) (m) For storage tanks, except as provided in 

paragraph (m)(4) of this section, calculate CH4

emissions using the applicable methods in 

paragraphs (m)(1) through (m)(3) of this section.

(m) For storage tanks, except as provided in 

paragraph (m)(3) of this section, calculate CH4

emissions using the applicable methods in 

paragraphs (m)(1) and (m)(2) of this section.

Corrects cross-reference

Y 98.256(f)(6) (6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology, the CO2 annual emissions as measured 

by the CEMS (unadjusted to remove CO2

combustion emissions associated with additional 

units, if present) and the process CO2 emissions as 

calculated according to §98.253(c)(1)(ii). Report the 

CO2 annual emissions associated with sources other 

than those from the coke burn-off in the applicable 

(6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology, the CO2 annual emissions as measured 

by the CEMS (unadjusted to remove CO2

combustion emissions associated with additional 

units, if present) and the process CO2 emissions as 

calculated according to §98.253(c)(1)(ii). Report the 

CO2 annual emissions associated with sources other 

than those from the coke burn-off in accordance with 

Clarifies reporting requirements
43

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

subpart (e.g., subpart C of this part in the case of a 

CO boiler).

the applicable subpart (e.g., subpart C of this part in 

the case of a CO boiler).

Y 98.256(h) (h) For sulfur recovery plants and for emissions from 

sour gas sent off-site for sulfur recovery, the owner 

and operator shall report:

(h) For on-site sulfur recovery plants and for 

emissions from sour gas sent off-site for sulfur 

recovery, the owner and operator shall report:

See preamble text for explanation

Y 98.256(h)(2) (2) Maximum rated throughput of each independent 

sulfur recovery plant, in metric tons sulfur 

produced/stream day, a description of the type of 

sulfur recovery plant, and an indication of the 

method used to calculate CO2 annual emissions for 

the sulfur recovery plant (e.g., CO2 CEMS, Equation 

Y–12, or process vent method in §98.253(j)).

(2) For each on-site sulfur recovery plant, the 

maximum rated throughput (metric tons sulfur 

produced/stream day), a description of the type of 

sulfur recovery plant, and an indication of the 

method used to calculate CO2 annual emissions for 

the sulfur recovery plant (e.g., CO2 CEMS, Equation 

Y–12, or process vent method in §98.253(j)).

See preamble text for explanation

Y 98.256(h)(3) (3) The calculated CO2 annual emissions for each 

sulfur recovery plant, expressed in metric tons. The 

calculated annual CO2 emissions from sour gas sent 

off-site for sulfur recovery, expressed in metric tons.

(3) The calculated CO2 annual emissions for each 

on-site sulfur recovery plant, expressed in metric 

tons. The calculated annual CO2 emissions from sour 

gas sent off-site for sulfur recovery, expressed in 

metric tons.

See preamble text for explanation

Y 98.256(h)(4) (4) If you use Equation Y–12 of this subpart, the 

annual volumetric flow to the sulfur recovery plant 

(in scf/year), the molar volume conversion factor (in 

scf/kg-mole), and the annual average mole fraction 

of carbon in the sour gas (in kg-mole C/kg-mole 

gas).

(4) If you use Equation Y–12 of this subpart, the 

annual volumetric flow to the on-site and off-site 

sulfur recovery plant (in scf/year), the molar volume 

conversion factor (in scf/kg-mole), and the annual 

average mole fraction of carbon in the sour gas (in 

kg-mole C/kg-mole gas).

See preamble text for explanation

Y 98.256(h)(5) (5) If you recycle tail gas to the front of the sulfur 

recovery plant, indicate whether the recycled flow 

rate and carbon content are included in the measured 

data under §98.253(f)(2) and (3). Indicate whether a 

correction for CO2 emissions in the tail gas was used 

in Equation Y–12. If so, then report the value of the 

correction, the annual volume of recycled tail gas (in 

scf/year) and the annual average mole fraction of 

carbon in the tail gas (in kg-mole C/kg-mole gas). 

Indicate whether you used the default (95%) or a unit 

specific correction, and if used, report the approach 

used.

(5) If you recycle tail gas to the front of an on-site 

sulfur recovery plant, indicate whether the recycled 

flow rate and carbon content are included in the 

measured data under §98.253(f)(2) and (3). Indicate 

whether a correction for CO2 emissions in the tail gas 

was used in Equation Y–12. If so, then report the 

value of the correction, the annual volume of 

recycled tail gas (in scf/year) and the annual average 

mole fraction of carbon in the tail gas (in kg-mole 

C/kg-mole gas). Indicate whether you used the 

default (95%) or a unit specific correction, and if a 

unit specific correction is used, report the approach 

used.

See preamble text for explanation

Y 98.256(h)(6) (6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology, the CO2 annual emissions as measured 

(6) If you use a CEMS, the relevant information 

required under §98.36 for the Tier 4 Calculation 

Methodology, the CO2 annual emissions as measured 

Clarifies reporting requirements
44

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

by the CEMS and the annual process CO2 emissions 

calculated according to §98.253(f)(1). Report the 

CO2 annual emissions associated with fuel 

combustion subpart C of this part (General 

Stationary Fuel Combustion Sources).

by the CEMS and the annual process CO2 emissions 

calculated according to §98.253(f)(1). Report the 

CO2 annual emissions associated with fuel 

combustion in accordance with subpart C of this part 

(General Stationary Fuel Combustion Sources).

Y 98.256(j) (10) (None) (10)If you use Equation Y-19 of this subpart, the 

relevant information required under paragraph (l)(5) 

of this section.

See preamble text for explanation

Y 98.256(k)(4) (4) For each set of coking drums that are the same 

dimensions: The number of coking drums in the set, 

the height and diameter of the coke drums (in feet), 

the cumulative number of vessel openings for all 

delayed coking drums in the set, the typical venting 

pressure (in psig), void fraction (in cf gas/cf of 

vessel), and the mole fraction of methane in coking 

gas (in kg-mole CF4/kg-mole gas, wet basis).

(4) For each set of coking drums that are the same 

dimensions: The number of coking drums in the set, 

the height and diameter of the coke drums (in feet), 

the cumulative number of vessel openings for all 

delayed coking drums in the set, the typical venting 

pressure (in psig), void fraction (in cf gas/cf of 

vessel), and the mole fraction of methane in coking 

gas (in kg-mole CH4/kg-mole gas, wet basis).

Corrects typographical error (CF4 to CH4)

Y 98.256(k)(6) (None) (6) If you use Equation Y-19 of this subpart, the 

relevant information required under paragraph (l)(5) 

of this section for each set of coke drums or vessels 

of the same size.

See preamble text for explanation

Y 98.256(o)(4)(

vi)

(vi) If you did not use Equation Y–23, the tankspecific methane composition data and the gas 

generation rate data used to estimate the cumulative 

CH4 emissions for storage tanks used to process 

unstabilized crude oil.

(vi) If you did not use Equation Y–23, the tankspecific methane composition data and the annual 

gas generation volume (scf/yr) used to estimate the 

cumulative CH4 emissions for storage tanks used to 

process unstabilized crude oil.

Clarifies reporting requirements

Y 98.256(o)(5), 

(6), (7)

(5) The method used to calculate the reported storage 

tank emissions for storage tanks processing 

unstabilized crude oil.

(6) The quantity of unstabilized crude oil received 

during the calendar year (in MMbbl), the average 

pressure differential (in psi), and the mole fraction of 

CH4 in vent gas from the unstabilized crude oil 

storage tank, and the basis for the mole fraction.

(7) The tank-specific methane composition data and 

the gas generation rate data, if you did not use 

Equation Y–23.

(5) [Reserved]

[6) [Reserved]

(7) [Reserved]

Removes duplicate reporting requirements.

Z 98.263(b)(1)(

ii)

(ii) If your process measurement provides the CO2

emissions directly as an output...

CO2 n,i = Carbon dioxide emissions of a grab sample 

(ii) If your process measurement provides the CO2

content directly as an output...

CO2 n,i = Carbon dioxide content of a grab sample 

See preamble text for explanation
45

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

batch of phosphate rock by origin i obtained during 

month n (percent by weight, expressed as a decimal 

fraction).

batch of phosphate rock by origin i obtained during 

month n (percent by weight, expressed as a decimal 

fraction).

Z 98.264(a) (a) You must obtain a monthly grab sample of 

phosphate rock directly from the rock being fed to 

the process line before it enters the mill using one of 

the following methods. You may conduct the 

representative bulk sampling using a method 

published by a consensus standards organization, or 

you may use industry consensus standard practice 

methods, including but not limited to the Phosphate 

Mining States Methods Used and Adopted by the 

Association of Fertilizer and Phosphate Chemists 

(AFPC) (P.O. Box 1645, Bartow, Florida 33831, 

(863) 534–9755, http://afpc.net, 

paul.mcafee@mosaicco.com). If phosphate rock is 

obtained from more than one origin in a month, you 

must obtain a sample from each origin of rock or 

obtain a composite representative sample.

(a) You must obtain a monthly grab sample of 

phosphate rock directly from the rock being fed to 

the process line before it enters the mill using one of 

the following methods. You may conduct the 

representative bulk sampling using a method 

published by a consensus standards organization, or 

you may use industry consensus standard practice 

methods, including but not limited to the Phosphate 

Mining States Methods Used and Adopted by the 

Association of Fertilizer and Phosphate Chemists 

(AFPC). If phosphate rock is obtained from more 

than one origin in a month, you must obtain a sample 

from each origin of rock or obtain a composite 

representative sample.

Deletes outdated contact information

Z 98.264(b) (b) You must determine the carbon dioxide or 

inorganic carbon content of each monthly grab 

sample of phosphate rock (consumed in the 

production of phosphoric acid). You may use a 

method published by a consensus standards 

organization, or you may use industry consensus 

standard practice methods, including but not limited 

to the Phosphate Mining States Methods Used and 

Adopted by AFPC (P.O. Box 1645, Bartow, Florida 

33831, (863) 534–9755, http://afpc.net, 

paul.mcafee@mosaicco.com).

(b) You must determine the carbon dioxide or 

inorganic carbon content of each monthly grab 

sample of phosphate rock (consumed in the 

production of phosphoric acid). You may use a 

method published by a consensus standards 

organization, or you may use industry consensus 

standard practice methods, including but not limited 

to the Phosphate Mining States Methods Used and 

Adopted by AFPC.

Deletes outdated contact information

Z 98.265(a) (a) For each missing value of the inorganic carbon 

content of phosphate rock or carbon dioxide (by 

origin), you must use the appropriate default factor 

provided in Table Z–1 this subpart. Alternatively, 

you must determine a substitute data value by 

calculating the arithmetic average of the qualityassured values of inorganic carbon contents of 

phosphate rock of origin i from samples immediately 

preceding and immediately following the missing 

A complete record of all measured parameters used 

in the GHG emissions calculations is required. 

Therefore, whenever a quality-assured value of a 

required parameter is unavailable, a substitute data 

value for the missing parameter must be used in the 

calculations as specified in paragraphs (a) and (b) of 

this section. 

(a) For each missing value of the inorganic carbon 

content or CO2 content of phosphate rock (by origin), 

Correction; clarifies the general requirement for 

missing data, removes a duplicate paragraph, 

clarifies the data element of inorganic carbon content 

may also be represented by CO2 content, and corrects 

the equation reference. 
46

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

data incident. You must document and keep records 

of the procedures used for all such estimates.

(a) For each missing value of the inorganic carbon 

content of phosphate rock (by origin), you must use 

the appropriate default factor provided in Table Z–1 

of this subpart. Alternatively, the you must determine 

substitute data value by calculating the arithmetic 

average of the quality-assured values of inorganic 

carbon contents of phosphate rock of origin i (see 

Equation Z–1 of this subpart) from samples 

immediately preceding and immediately following 

the missing data incident. If no quality-assured data 

on inorganic carbon contents of phosphate rock of 

origin i are available prior to the missing data 

incident, the substitute data value shall be the first 

quality-assured value for inorganic carbon contents 

for phosphate rock of origin i obtained after the 

missing data period.

you must use the appropriate default factor provided 

in Table Z–1 of this subpart. Alternatively, you must 

determine a substitute data value by calculating the 

arithmetic average of the quality-assured values of 

inorganic carbon contents or CO2 contents of 

phosphate rock of origin i (see Equation Z–1a or Z1b of this subpart) from samples immediately 

preceding and immediately following the missing 

data incident. If no quality-assured data on inorganic 

carbon contents or CO2 contents of phosphate rock 

of origin i are available prior to the missing data 

incident, the substitute data value shall be the first 

quality-assured value for inorganic carbon contents 

or CO2 contents for phosphate rock of origin i 

obtained after the missing data period.

Z 98.266(a) (a) Annual phosphoric acid production by origin (as 

listed in Table Z–1 to this subpart) of the phosphate 

rock (tons).

(a) Annual phosphoric acid production, by origin of 

the phosphate rock (tons).

Removes a reference to Table Z-1. The reporting 

element could have a place of origin other than those 

listed in Table Z-1

Z 98.266(b) (b) Annual phosphoric acid permitted production 

capacity (tons)

(b) Annual phosphoric acid production capacity 

(tons)

See preamble text for explanation

Z 98.266(d) (d) Annual phosphate rock consumption from 

monthly measurement records by origin, (as listed in 

Table Z–1 to this subpart) (tons).

(d) Annual phosphate rock consumption from 

monthly measurement records by origin (tons).

Clarifies reporting requirements

Z 98.266(f)(5) (5) Monthly inorganic carbon content of phosphate 

rock for each wet-process phosphoric acid process 

line for which Equation Z–1a is used (percent by 

weight, expressed as a decimal fraction), or CO2

(percent by weight, expressed as a decimal fraction) 

for which Equation Z–1b is used.

(5) Monthly inorganic carbon content of phosphate 

rock for each wet-process phosphoric acid process 

line for which Equation Z–1a is used (percent by 

weight, expressed as a decimal fraction), or CO2

content (percent by weight, expressed as a decimal 

fraction) for which Equation Z–1b is used.

Clarifies reporting requirements

Z 98.266(f)(6) (6) Monthly mass of phosphate rock consumed by 

origin, (as listed in Table Z–1 of this subpart) in 

production for each wet-process phosphoric acid 

process line (tons).

(6) Monthly mass of phosphate rock consumed, by 

origin, in production for each wet-process 

phosphoric acid process line (tons).

Clarifies reporting requirements

Z 98.266(f)(8) (8) Number of times missing data procedures were 

used to estimate phosphate rock consumption 

(months) and inorganic carbon contents of the 

(8) Number of times missing data procedures were 

used to estimate phosphate rock consumption

(months), inorganic carbon contents of the phosphate 

Adds reporting requirement for missing data 

procedures
47

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

phosphate rock (months). rock (months), and CO2 contents of the phosphate 

rock (months).

Z 98.267(a) (a) Monthly mass of phosphate rock consumed by 

origin (as listed in Table Z–1 of this subpart) (tons).

(a) Monthly mass of phosphate rock consumed by 

origin (tons).

Removes a reference to Table Z-1. The reporting 

element could have a place of origin other than those 

listed in Table Z-1

Z 98.26(c ) (c) Documentation of the procedures used to ensure 

the accuracy of monthly phosphate rock 

consumption by origin, (as listed in Table Z–1 of this 

subpart).

(c) Documentation of the procedures used to ensure 

the accuracy of monthly phosphate rock 

consumption by origin.

Removes a reference to Table Z-1. The reporting 

element could have a place of origin other than those 

listed in Table Z-1

AA 98.273(a)(3) (3) Calculate biogenic CO2 emissions and emissions 

of CH4 and N2O from biomass using measured 

quantities of spent liquor solids fired, site-specific 

HHV, and default or site-specific emissions factors, 

according to Equation AA–1 of this section:

***

(Variable from Equation AA-1:) 

(EF) = Default or site-specific emission factor for 

CO2, CH4, or N2O, from Table AA–1 of this subpart 

(kg CO2, CH4, or N2O per mmBtu).

(3) Calculate biogenic CO2 emissions and emissions 

of CH4 and N2O from biomass using measured 

quantities of spent liquor solids fired, site-specific 

HHV, and default emissions factors, according to 

Equation AA–1 of this section:

***

(Variable from Equation AA-1:) 

(EF) = Default emission factor for CO2, CH4, or 

N2O, from Table AA–1 of this subpart (kg CO2, CH4, 

or N2O per mmBtu).

See preamble text for explanation

AA 98.276(e) (e) The default or site-specific emission factor for 

CO2, CH4, or N2O, used in Equation AA–1 of this 

subpart (kg CO2, CH4, or N2O per mmBtu).

(e) The default emission factor for CO2, CH4, or 

N2O, used in Equation AA–1 of this subpart (kg 

CO2, CH4, or N2O per mmBtu).

Harmonize with change made to 98.273(a)(3)

AA 98.276(k) (k) Annual production of pulp and/or paper products 

produced (metric tons).

(k) Annual production of pulp and/or paper products 

produced (metric tons) as follows:

(1) Report the total annual production of unbleached 

virgin pulp produced onsite during the reporting year 

in air-dried metric tons per year. This total annual 

production value is the sum of all kraft, 

semichemical, soda, and sulfite pulp produced onsite, 

prior to bleaching, through all virgin pulping lines.

(i) Do not include secondary fiber repulped for paper 

production in the virgin pulp production total. 

(ii) You must report a positive (non-zero) value for 

pulp production unless your pulp mill did not operate 

during the reporting year. 

(2) Report the total annual production of paper 

products exiting the paper machine(s), prior to 

application of any off-machine coatings, in air-dried 

See preamble text for explanation
48

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

metric tons per year. If you operate multiple paper 

machines, report the sum (total) of the air-dried 

metric tons of paper produced during the reporting 

year for all paper machines at the mill.

AA Tables AA-1 

& AA-2

See Tables AA-1 and AA-2 in the current rule file. See Appendix A for changes to Table AA-1 and AA2See preamble text for explanation

BB 98.282(a) (a) CO2 and CH4 process emissions from all silicon 

carbide process units or furnaces combined. 

(a) CO2 process emissions from all silicon carbide 

process units or furnaces combined. 

See preamble text for explanation

BB 98.283

Introductory 

paragraph

98.283 Calculating GHG Emissions. 

You must calculate and report the annual process 

CO2 emissions from each silicon carbide process unit 

or production furnace using the procedures in either 

paragraph (a) or (b) of this section. You must 

determine CH4 process emissions in accordance with 

the procedures specified in paragraph (d) of this 

section.

98.283 Calculating GHG Emissions. 

You must calculate and report the combined annual 

process CO2 emissions from all silicon carbide 

process units and production furnaces using the 

procedures in either paragraph (a) or (b) of this 

section.

See preamble text for explanation

BB 98.283(a) (a) Calculate and report under this subpart the 

process CO2 emissions by operating and maintaining 

CEMS according to the Tier 4 Calculation 

Methodology specified in §98.33(a)(4) and all 

associated requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel Combustion 

Sources).

(a) Calculate and report under this subpart the 

combined annual process CO2 emissions by 

operating and maintaining CEMS according to the 

Tier 4 Calculation Methodology specified in 

§98.33(a)(4) and all associated requirements for Tier 

4 in subpart C of this part (General Stationary Fuel 

Combustion Sources).

Harmonizing change with 98.283 introductory 

paragraph. 

BB 98.283(b) (b) Calculate and report under this subpart the 

process CO2 emissions using the procedures in 

paragraphs (b)(1) and (b)(2) of this section.

(b) Calculate and report under this subpart the 

combined annual process CO2 emissions using the 

procedures in paragraphs (b)(1) and (b)(2) of this 

section.

Harmonizing change with 98.283 introductory 

paragraph. 

BB 98.283(b)(2) (2) Use Equation BB–2 of this section to calculate 

annual CO2 process emissions from all silicone 

carbide production:

(2) Calculate annual CO2 process emissions from the 

silicon carbide production facility according to 

Equation BB-2 of this section:

Corrects misspelling and clarifies requirement

BB 98.283(b)(2) Tn = Petroleum coke consumption in month n(tons) Tn = Petroleum coke consumption in calendar month 

n(tons)

Clarifies equation term

BB 98.283(d) (d) You must calculate annual process CH4

emissions from all silicon carbide production 

combined using Equation BB–3 of this section:

Eq. BB-3

(d) [Reserved] See preamble text for explanation

BB 98.286(b) (b) If a CEMS is not used to measure process CO2

emissions, you must report the information listed in 

(b) If a CEMS is not used to measure process CO2

emissions, you must report the information in 

Correction for consistency with 40 CFR 98.282. 
49

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

this paragraph (b) for all furnaces combined: paragraph (b)(1) through (b)(8) of this section for all 

silicon carbide process units or production furnaces 

combined:

DD 98.304(c)(1) (1) Ensure that cylinders returned to the gas supplier 

are consistently weighed on a scale that is certified to 

be accurate and precise to within 2 pounds of the 

scale's capacity and is periodically recalibrated per 

the manufacturer's specifications. Either measure 

residual gas (the amount of gas remaining in returned 

cylinders) or have the gas supplier measure it. If the 

gas supplier weighs the residual gas, obtain from the 

gas supplier a detailed monthly accounting, within ± 

2 pounds, of residual gas amounts in the cylinders 

returned to the gas supplier.

(1) Ensure that cylinders returned to the gas supplier 

are consistently weighed on a scale that is certified to 

be accurate and precise to within 2 pounds of true 

weight and is periodically recalibrated per the 

manufacturer's specifications. Either measure 

residual gas (the amount of gas remaining in returned 

cylinders) or have the gas supplier measure it. If the 

gas supplier weighs the residual gas, obtain from the 

gas supplier a detailed monthly accounting, within ± 

2 pounds, of residual gas amounts in the cylinders 

returned to the gas supplier.

See preamble text for explanation

DD 98.304(c)(2) (2) Ensure that cylinders weighed for the beginning 

and end of year inventory measurements are weighed 

on a scale that is certified to be accurate to within 2 

pounds of the scale's capacity and is periodically 

recalibrated per the manufacturer's specifications. All 

scales used to measure quantities that are to be 

reported under §98.306 must be calibrated using 

calibration procedures specified by the scale 

manufacturer. Calibration must be performed prior to 

the first reporting year. After the initial calibration, 

recalibration must be performed at the minimum 

frequency specified by the manufacturer.

(2) Ensure that cylinders weighed for the beginning 

and end of year inventory measurements are weighed 

on a scale that is certified to be accurate and precise 

to within 2 pounds of true weight and is periodically 

recalibrated per the manufacturer's specifications. All 

scales used to measure quantities that are to be 

reported under §98.306 must be calibrated using 

calibration procedures specified by the scale 

manufacturer. Calibration must be performed prior to 

the first reporting year. After the initial calibration, 

recalibration must be performed at the minimum 

frequency specified by the manufacturer.

See preamble text for explanation

FF 98.320(b)(1) (1) Each ventilation well or shaft, including both 

those wells and shafts where gas is emitted and those 

where gas is sold, used onsite, or otherwise 

destroyed (including by flaring).

(1) Each ventilation system shaft or vent hole, 

including both those points where mine ventilation 

air is emitted and those where it is sold, used onsite, 

or otherwise destroyed (including by ventilation air 

methane (VAM) oxidizers).

See preamble text for explanation

FF 98.320(b)(2) (2) Each degasification system well or shaft, 

including degasification systems deployed before, 

during, or after mining operations are conducted in a 

mine area. This includes both those wells and shafts 

where gas is emitted, and those where gas is sold, 

used onsite, or otherwise destroyed (including by 

flaring).

(2) Each degasification system well or gob gas vent 

hole, including degasification systems deployed 

before, during, or after mining operations are 

conducted in a mine area. This includes both those 

wells and vent holes where coal bed gas is emitted, 

and those where the gas is sold, used onsite, or 

otherwise destroyed (including by flaring).

See preamble text for explanation
50

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

FF 98.322(b) (b) You must report CH4 destruction from systems 

where gas is sold, used onsite, or otherwise 

destroyed (including by flaring).

(b) You must report CH4 destruction from systems 

where gas is sold, used onsite, or otherwise 

destroyed (including by VAM oxidation and by 

flaring).

See preamble text for explanation

FF 98.322(d) (d) You must report under this subpart the CO2

emissions from coal mine gas CH4 destruction 

occurring at the facility, where the gas is not a fuel 

input for energy generation or use ( e.g., flaring).

(d) You must report under this subpart the CO2

emissions from coal mine gas CH4 destruction 

occurring at the facility, where the gas is not a fuel 

input for energy generation or use ( e.g., flaring and 

VAM oxidation).

See preamble text for explanation

FF 98.323(a) V = Volumetric flow rate for the quarter (cfm) based 

on sampling or a flow rate meter. If a flow rate meter 

is used and the meter automatically corrects for 

temperature and pressure, replace ―520°R/T × P/1 

atm‖ with ―1‖.

V = Volumetric flow rate for the quarter (acfm) 

based on sampling or a flow rate meter. If a flow rate 

meter is used and the meter automatically corrects to 

standard temperature and pressure, then use scfm and 

replace ―520°R/T × P/1 atm‖ with ―1‖. 

Clarifies an equation term

FF 98.323(a) MCF = Moisture correction factor for the 

measurement period, volumetric basis.

= 1 when V and C are measured on a dry basis or if 

both are measured on a wet basis.= 1-(fH2O)n when V 

is measured on a wet basis and C is measured on a 

dry basis.= 1/[1-(fH2O)] when V is measured on a dry 

basis and C is measured on a wet basis.

MCF = Moisture correction factor for the 

measurement period, volumetric basis.

= 1 when V and C are measured on a dry basis or if 

both are measured on a wet basis.= 1-(fH2O) when V 

is measured on a wet basis and C is measured on a 

dry basis.= 1/[1-(fH2O)] when V is measured on a dry 

basis and C is measured on a wet basis.

Corrects subscript errors

FF 98.323(a) (fH2O) = Moisture content of the methane emitted 

during the measurement period, volumetric basis 

(cubic feet water per cubic feet emitted gas).

(fH2O) = Moisture content of the methane emitted 

during the measurement period, volumetric basis 

(cubic feet water per cubic feet emitted gas).

Corrects subscript errors

FF 98.323(a) P = Pressure at which flow is measured (atm) for the 

quarter. The annual average barometric pressure 

from the nearest NOAA weather service station may 

be used as a default.

P = Absolute pressure at which flow is measured 

(atm) for the quarter. The annual average barometric 

pressure from the nearest NOAA weather service 

station may be used as a default.

See preamble text for explanation

FF 98.323(a)(2) (2) Values of V, C, T, P, and (fH2O), if applicable... (2) Values of V, C, T, P, and (fH2O), if applicable... Corrects subscript errors

FF 98.323(b) 

Equation FF3

T Ti Corrects subscript errors

FF 98.323(b) Vi= Measured volumetric flow rate for the days in 

the week when the degasification system is in 

operation at that monitoring point, based on 

sampling or a flow rate meter (cfm). If a flow rate 

Vi= Measured volumetric flow rate for the days in 

the week when the degasification system is in 

operation at that monitoring point, based on 

sampling or a flow rate meter (acfm). If a flow rate 

Clarification of equation term
51

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

meter is used and the meter automatically corrects 

for temperature and pressure, replace ―520°R/Ti× 

Pi/1 atm‖ with ―1‖.

meter is used and the meter automatically corrects to 

standard temperature and pressure, then use scfm and 

replace ―520°R/Ti× Pi/1 atm‖ with ―1‖.

FF 98.323(b) fH2O fH2O Corrects subscript errors

FF 98.323(b) Pi = Pressure at which flow is measured (atm). Pi = Absolute pressure at which flow is measured 

(atm).

Clarifies an equation term

FF 98.323(b)(1) (1) Values of V, C, T, P, and (fH2O), if applicable 

must be based on measurements taken at least once 

each quarter with no fewer than 6 weeks between 

measurements. If measurements are taken more 

frequently than once per quarter, then use the 

average value for all measurements taken. If 

continuous measurements are taken, then use the 

average value over the time period of continuous 

monitoring.

(1) Values of V, C, T, P, and (fH2O), if applicable 

must be based on measurements taken at least once 

each quarter with no fewer than 6 weeks between 

measurements. If measurements are taken more 

frequently than once per quarter, then use the 

average value for all measurements taken. If 

continuous measurements are taken, then use the 

average value over the time period of continuous 

monitoring.

Corrects subscript errors and typographical error.

FF 98.323(b)(2) CH4D (CH4D)i.j Corrects subscript errors

FF 98.323(c) (c) If gas from degasification system wells or 

ventilation shafts is sold, used onsite, or otherwise 

destroyed (including by flaring), you must calculate 

the quarterly CH4 destroyed for each destruction 

device and each point of offsite transport to a 

destruction device, using Equation FF–5 of this 

section. You must measure CH4 content and flow 

rate according to the provisions in §98.324, and 

calculate the methane routed to the destruction 

device (CH4) using either Equation FF–1 or Equation 

FF–3 of this section, as applicable.

(c) If gas from a degasification system or ventilation 

system is sold, used onsite, or otherwise destroyed 

(including by flaring or VAM oxidation), you must 

calculate the quarterly CH4 destroyed for each 

destruction device and each point of offsite transport 

to a destruction device, using Equation FF–5 of this 

section. You must measure CH4 content and flow 

rate according to the provisions in §98.324, and 

calculate the methane routed to the destruction 

device (CH4) using either Equation FF–1 or Equation 

FF–4 of this section, as applicable.

Clarifies terminology and equation reference
52

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

FF 98.323 (c ) 

Equation FF6

Corrects equation term

FF 98.324(b) (b) For CH4 liberated from ventilation systems, 

determine whether CH4 will be monitored from each 

ventilation well and shaft, from a centralized 

monitoring point, or from a combination of the two 

options. Operators are allowed flexibility for 

aggregating emissions from more than one 

ventilation well or shaft, as long as emissions from 

all are addressed, and the methodology for 

calculating total emissions documented. Monitor by 

one of the following options:

(b) For CH4 liberated from ventilation systems, 

determine whether CH4 will be monitored from each 

ventilation shaft and vent hole, from a centralized 

monitoring point, or from a combination of the two 

options. Operators are allowed flexibility for 

aggregating emissions from more than one 

ventilation point, as long as emissions from all are 

addressed, and the methodology for calculating total 

emissions documented. Monitor by one of the 

following options:

Clarifies rule text.

FF 98.324(c)(2) (2) Collect weekly (once each calendar week, with at 

least three days between measurements) or more 

frequent samples, for all degasification wells and gob 

gas vent holes. Determine weekly or more frequent 

flow rates, methane concentration, temperature, and 

pressure from these degasification wells and gob gas 

vent holes. Methane composition should be 

determined either by submitting samples to a lab for 

analysis, or from the use of methanometers at the 

degasification well site. Follow the sampling 

protocols for sampling of methane emissions from 

ventilation shafts, as described in §98.324(b)(1). You 

must record the date of sampling, flow, temperature, 

pressure, and moisture measurements, the methane 

concentration (percent), the bottle number of samples 

collected, and the location of the measurement or 

(2) Collect weekly (once each calendar week, with at 

least three days between measurements) or more 

frequent samples, for all degasification wells and gob 

gas vent holes. Determine weekly or more frequent 

flow rates, methane concentration, temperature, and 

pressure from these degasification wells and gob gas 

vent holes. Methane composition should be 

determined either by submitting samples to a lab for 

analysis, or from the use of methanometers at the 

degasification monitoring site. Follow the sampling 

protocols for sampling of methane emissions from 

ventilation shafts, as described in §98.324(b)(1). You 

must record the date of sampling, flow, temperature, 

pressure, and moisture measurements, the methane 

concentration (percent), the bottle number of samples 

collected, and the location of the measurement or 

Clarifies rule text.
53

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

collection. collection.

FF 98.324(d)(2)(

iii)

CCH4 CCH4Corrects subscript errors

FF 98.326(a) (a) Quarterly CH4 liberated from each ventilation 

monitoring point (CH4Vm), (metric tons CH4).

(a) Quarterly CH4 liberated from each ventilation 

monitoring point, (metric tons CH4).

Clarifies rule text

FF 98.326(f) (f) Quarterly volumetric flow rate for each 

ventilation monitoring point (scfm), date and 

location of each measurement, and method of 

measurement (quarterly sampling or continuous 

monitoring), used in Equation FF–1 of this subpart. 

(f) Quarterly volumetric flow rate for each 

ventilation monitoring point and units of measure 

(scfm or acfm), date and location of each 

measurement, and method of measurement (quarterly 

sampling or continuous monitoring), used in 

Equation FF–1 of this subpart. 

Harmonizes reporting requirement with equations. 

FF 98.326(h) (h) Weekly volumetric flow rate used to calculate 

CH4 liberated from degasification systems (cfm) and 

method of measurement (sampling or continuous 

monitoring), used in Equation FF–3 of this subpart. 

(h) Weekly volumetric flow rate used to calculate 

CH4 liberated from degasification systems and units 

of measure (acfm or scfm), and method of 

measurement (sampling or continuous monitoring), 

used in Equation FF–3 of this subpart. 

Harmonizes reporting requirement with equations

FF 98.326(i) (i) Quarterly CEMS CH4 concentration (%) used to 

calculate CH4 liberated from degasification systems 

(average from daily data), or quarterly CH4

concentration data based on results from weekly 

sampling data) (C).

(i) Quarterly CH4 concentration (%) used to calculate 

CH4 liberated from degasification systems and if the 

data is based on CEMS or weekly sampling.

Includes the basis of the concentration data in the 

report. 

FF 98.326(j) (j) Weekly volumetric flow rate used to calculate 

CH4 destruction for each destruction device and each 

point of offsite transport (cfm).

(j) Weekly volumetric flow rate used to calculate 

CH4 destruction for each destruction device and each 

point of offsite transport, and units of measure (acfm 

or scfm). 

Harmonizes reporting requirement with equations.

FF 98.326(o) (o) Temperatures (°R), pressure (atm), and moisture 

content used in Equation FF–1 and FF–3 of this 

subpart, and the gaseous organic concentration 

correction factor, if Equation FF–9 was required.

(o) Temperatures (°R), pressure (atm), moisture 

content, and the moisture correction factor (if 

applicable) used in Equation FF–1 and FF–3 of this 

subpart; and the gaseous organic concentration 

correction factor, if Equation FF–9 was required.

See preamble text for explanation

FF 98.326(r) (r) Identification information and description for 

each well and shaft, indication of whether the well or 

shaft is monitored individually, or as part of a 

centralized monitoring point. Note which method 

(sampling or continuous monitoring) was used.

(r) Identification information and description for 

each well and shaft, including paragraphs (r)(1) 

through (r)(3) of this section:

(1) Indication of whether the well or shaft is 

monitored individually, or as part of a centralized 

monitoring point. Note which method (sampling or 

See preamble text for explanation
54

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

continuous monitoring) was used.

(2) Start date and close date of each well or shaft.

(3) Number of days the well or shaft was in 

operation during the reporting year.

FF 98.326(t) No current requirement (t) Quarterly CH4 routed to each destruction device 

or offsite transfer point used in Equation FF-5 of this 

subpart (metric tons). 

See preamble text for explanation

FF 98.326(u) No current requirement (u) Mine Safety and Health Administration (MSHA) 

identification for this coal mine

See preamble text for explanation

HH 98.343(a)(1) 

Equation HH1

DOC = Degradable organic carbon from Table HH-1 

of this subpart or measurement data, if available 

[fraction (metric tons C/metric ton waste)].

DOC = Degradable organic carbon from Table HH-1 

of this subpart [fraction (metric tons C/metric ton 

waste)].

See preamble text for explanation

HH Equation HH1, 98.345F = Fraction by volume of CH4 in landfill gas from 

measurement data on a dry basis, if available 

(fraction); default is 0.5.

F = Fraction by volume of CH4 in landfill gas from 

measurement data for the current reporting year, if 

available (fraction, dry basis, corrected to 0 percent 

oxygen); otherwise, use the default of 0.5.

See preamble text for explanation

HH 98.343(b)(1) 

Equation HH4

(C)n (CCH4)n Corrects equation term

HH 98.343(b)(1) 

Equation HH4

N = Total number of measurement periods in a year. 

Use daily averaging periods for a continuous 

monitoring system and N=365 (or N = 366 for leap 

years). For weekly sampling, as provided in 

paragraph (b)(2) of this section, use N=52.

N = Total number of measurement periods in a year. 

Use daily averaging periods for a continuous 

monitoring system and N=365 (or N = 366 for leap 

years). For monthly sampling, as provided in 

paragraph (b)(2) of this section, use N=12.

See preamble text for explanation

HH HH-4 0.0423 = Density of CH4 lb/cfm at 520°R or 60 

degrees Fahrenheit and 1 atm.

0.0423 = Density of CH4 lb/cf at 520°R or 60 

degrees Fahrenheit and 1 atm.

Corrects typographical error

HH 98.343(b)(2)(

i)

(i) Continuously monitor gas flow rate and determine 

the cumulative volume of landfill gas each week and 

the cumulative volume of landfill gas each year that 

is collected and routed to a destruction device 

(before any treatment equipment). Under this option, 

the gas flow meter is not required to automatically 

correct for temperature, pressure, or, if necessary, 

moisture content. If the gas flow meter is not 

equipped with automatic correction for temperature, 

pressure, or, if necessary, moisture content, you must 

determine these parameters as specified in paragraph 

(b)(2)(iii) of this section.

(i) Continuously monitor gas flow rate and determine 

the cumulative volume of landfill gas each month 

and the cumulative volume of landfill gas each year 

that is collected and routed to a destruction device 

(before any treatment equipment). Under this option, 

the gas flow meter is not required to automatically 

correct for temperature, pressure, or, if necessary, 

moisture content. If the gas flow meter is not 

equipped with automatic correction for temperature, 

pressure, or, if necessary, moisture content, you must 

determine these parameters as specified in paragraph 

(b)(2)(iii) of this section.

Harmonizing change to accommodate monthly 

sampling of CH4 concentration
55

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

HH 98.343(b)(2)(

ii)

(ii) Determine the CH4 concentration in the landfill 

gas that is collected and routed to a destruction 

device (before any treatment equipment) in a 

location near or representative of the location of the 

gas flow meter at least once each calendar week; if 

only one measurement is made each calendar week, 

there must be at least three days between 

measurements.

(ii) Determine the CH4 concentration in the landfill 

gas that is collected and routed to a destruction 

device (before any treatment equipment) in a 

location near or representative of the location of the 

gas flow meter at least once each calendar month; if 

only one measurement is made each calendar month, 

there must be at least fourteen days between 

measurements.

Harmonizing change to accommodate monthly 

sampling of CH4 concentration

HH 98.343(b)(2)(

iii)(A)

(A) Determine the temperature and pressure in the 

landfill gas that is collected and routed to a 

destruction device (before any treatment equipment) 

in a location near or representative of the location of 

the gas flow meter at least once each calendar week; 

if only one measurement is made each calendar 

week, there must be at least three days between 

measurements. 

(A) Determine the temperature and pressure in the 

landfill gas that is collected and routed to a 

destruction device (before any treatment equipment) 

in a location near or representative of the location of 

the gas flow meter at least once each calendar month; 

if only one measurement is made each calendar 

month, there must be at least fourteen days between 

measurements. 

Harmonizing change to accommodate monthly 

sampling of CH4 concentration

HH 98.343(b)(2)(

iii)(B)

(B) If the CH4 concentration is determined on a dry 

basis and flow is determined on a wet basis or CH4

concentration is determined on a wet basis and flow 

is determined on a dry basis, and the flow meter does 

not automatically correct for moisture content, 

determine the moisture content in the landfill gas that 

is collected and routed to a destruction device 

(before any treatment equipment) in a location near 

or representative of the location of the gas flow 

meter at least once each calendar week; if only one 

measurement is made each calendar week, there 

must be at least three days between measurements.

(B) If the CH4 concentration is determined on a dry 

basis and flow is determined on a wet basis or CH4

concentration is determined on a wet basis and flow 

is determined on a dry basis, and the flow meter does 

not automatically correct for moisture content, 

determine the moisture content in the landfill gas that 

is collected and routed to a destruction device 

(before any treatment equipment) in a location near 

or representative of the location of the gas flow 

meter at least once each calendar month; if only one 

measurement is made each calendar month, there 

must be at least fourteen days between

measurements.

Harmonizing change to accommodate monthly 

sampling of CH4 concentration

HH 98.343(c )(1) 

(Eq. HH-5)

OX = Oxidation fraction. Use the default value of 

0.1 (10%).

OX = Oxidation fraction. Use the appropriate 

oxidation fraction default value from Table HH-4 of 

this subpart. 

See preamble text for explanation

HH 98.343(c 

)(3)(i)

(Eq. HH-6)

See preamble text for explanation

HH 98.343(c (None) N = Number of landfill gas measurement locations Harmonizing with changes to Equation HH-6 for 

Dest

CH

R DE f

G R

1

4

N

n

n n Dest n

N

n

CH n

R DE f

G R

1

,

1

1

4
56

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

)(3)(i)

(Eq. HH-6)

(associated with a destruction device or gas sent offsite). If a single monitoring location is used to 

monitor volumetric flow and CH4 concentration of 

the recovered gas sent to one or multiple destruction 

devices, then N=1.

multiple measurement locations and/or multiple 

destruction devices

HH 98.343(c 

)(3)(i)

(Eq. HH-6)

R = Quantity of recovered CH4 from Equation HH-4 

of this section (metric tons).

Rn = Quantity of recovered CH4 from Equation HH-4 

of this section for the nth measurement location 

(metric tons).

Harmonizing with changes to Equation HH-6 for 

multiple measurement locations and/or multiple 

destruction devices

HH 98.343(c 

)(3)(i)

(Eq. HH-6)

OX = OX = Oxidation fraction. Use the default 

value of 0.1 (10%).

OX = Oxidation fraction. Use the appropriate 

oxidation fraction default value from Table HH-4 of 

this subpart.

See preamble text for explanation

HH 98.343(c 

)(3)(i)

(Eq. HH-6)

DE = Destruction efficiency (lesser of manufacturer's 

specified destruction efficiency and 0.99). If the gas 

is transported off-site for destruction, use DE = 1. 

DEn = Destruction efficiency (lesser of 

manufacturer's specified destruction efficiency and 

0.99) for the nth measurement location. If the gas is 

transported off-site for destruction, use DE = 1. If the 

volumetric flow and CH4 concentration of the 

recovered gas is measured at a single location 

providing landfill gas to multiple destruction devices

(including some gas destroyed on-site and some gas 

sent off-site for destruction), calculate DEn as the 

arithmetic average of the DE values determined for 

each destruction device associated with that 

measurement location.

Harmonizing with changes to Equation HH-6 for 

multiple measurement locations and/or multiple 

destruction devices

HH 98.343(c 

)(3)(i)

(Eq. HH-6) 

fDest = Fraction of hours the destruction device was 

operating (annual operating hours / 8760 hours per 

year). If the gas is destroyed in a back-up flare (or 

similar device) or if the gas is transported off-site for 

destruction, use fDest = 1. 

fDest,n = Fraction of hours the destruction device 

associated with the nth measurement location was 

operating during active gas flow calculated as the 

annual operating hours for the destruction device 

divided by the annual hours flow was sent to the 

destruction device as measured at the nth 

measurement location. If the gas is destroyed in a 

back-up flare (or similar device) or if the gas is 

transported off-site for destruction, use fDest= 1. If the 

volumetric flow and CH4 concentration of the 

recovered gas is measured at a single location 

providing landfill gas to multiple destruction devices 

(including some gas destroyed on-site and some gas 

sent off-site for destruction), calculate fDest,n as the 

arithmetic average of the fDest values determined for 

Harmonizing with changes to Equation HH-6 for 

multiple measurement locations and/or multiple 

destruction devices and clarifies equation term to 

more accurately reflect operating hours of the gas 

collection system.
57

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

each destruction device associated with that 

measurement

HH 98.343(c 

)(3)(ii)

(Eq. HH-7)

See preamble for discussion

HH 98.343(c 

)(3)(ii)

(Eq. HH-8)

See preamble for discussion

HH 98.343(c 

)(3)(ii)

(Eq. HH-8)

(None) N = Number of landfill gas measurement locations 

(associated with a destruction device or gas sent offsite). If a single monitoring location is used to 

monitor volumetric flow and CH4 concentration of 

the recovered gas sent to one or multiple destruction 

devices, then N=1.

Harmonizing with changes to Equation HH-8 for 

multiple measurement locations and/or multiple 

destruction devices

HH 98.343(c 

)(3)(ii)

(Eq. HH-8)

R = Quantity of recovered CH4 from Equation HH-4 

of this section (metric tons CH4).

Rn = Quantity of recovered CH4 from Equation HH-4 

of this section for the nth measurement location 

(metric tons CH4).

Harmonizing with changes to Equation HH-8 for 

multiple measurement locations and/or multiple 

destruction devices

HH 98.343(c 

)(3)(ii)

(Eq. HH-8)

fRec = Fraction of hours the recovery system was 

operating (annual operating hours/8760 hours per 

year).

fRec,n = Fraction of hours the recovery system 

associated with the nth measurement location was 

operating (annual operating hours/8760 hours per 

year or annual operating hours / 8784 per year for a 

leap year).

Harmonizing with changes to Equation HH-8 for 

multiple measurement locations and/or multiple 

destruction devices

HH 98.343(c 

)(3)(ii)

(Eq. HH-8)

OX = Oxidation fraction. Use the default value of 

0.1 (10%).

OX = Oxidation fraction. Use appropriate oxidation 

fraction default value from Table HH-4 of this 

subpart.

See preamble text for explanation

HH 98.343(c 

)(3)(ii)

(Eq. HH-8)

DE = Destruction efficiency (lesser of manufacturer's 

specified destruction efficiency and 0.99). If the gas 

is transported off-site for destruction, use DE = 1. 

DEn = Destruction efficiency (lesser of 

manufacturer's specified destruction efficiency and 

0.99) for the nth measurement location. If the gas is 

transported off-site for destruction, use DE = 1. If the 

volumetric flow and CH4 concentration of the 

Harmonizing with changes to Equation HH-8 for 

multiple measurement locations and/or multiple 

destruction devices

N

n

n n Dest n

N

n

n

N

n c n

n

R DE f

R

f

R

CE

1

,

1 Re , 1

1

1

(1- OX)

f

R

CE

1 MG

1 Rec,n

n

N

n

Dest

c

DE f

R

CE f

R

1

Re N

n

n n Dest n

N

n

n

N

n c n

n

R DE f

R

f

R

CE

1

,

1 Re , 1

1

1
58

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

recovered gas is measured at a single location 

providing landfill gas to multiple destruction devices 

(including some gas destroyed on-site and some gas 

sent off-site for destruction), calculate DEn as the 

arithmetic average of the DE values determined for 

each destruction device associated with that 

measurement location.

HH 98.343(c)(3)(i

i) (Eq. HH-8)

FDest, = Fraction of hours the destruction device was 

operating (device operating hours/8760 hours per 

year). If the gas is destroyed in a back-up flare (or 

similar device) or if the gas is transported off-site for 

destruction, use fDest= 1.

fDest,n = Fraction of hours the destruction device 

associated with the nth measurement location was 

operating during active gas flow calculated as the 

annual operating hours for the destruction device 

divided by the annual hours flow was sent to the 

destruction device as measured at the nth 

measurement location. If the gas is destroyed in a 

back-up flare (or similar device) or if the gas is 

transported off-site for destruction, use fDest= 1. If the 

volumetric flow and CH4 concentration of the 

recovered gas is measured at a single location 

providing landfill gas to multiple destruction devices 

(including some gas destroyed on-site and some gas 

sent off-site for destruction), calculate fDest,n as the 

arithmetic average of the fDest values determined for 

each destruction device associated with that 

measurement location.

Harmonizing with changes to Equation HH-8 for 

multiple measurement locations and/or multiple 

destruction devices and clarifies equation term to 

more accurately reflect operating hours of gas 

collection system

HH 98.344(e) (e) The owner or operator shall document the 

procedures used to ensure the accuracy of the 

estimates of disposal quantities and, if applicable, 

gas flow rate, gas composition, temperature, 

pressure, and moisture content measurements. These 

procedures include, but are not limited to, calibration 

of weighing equipment, fuel flow meters, and other 

measurement devices. The estimated accuracy of 

measurements made with these devices shall also be 

recorded, and the technical basis for these estimates 

shall be provided.

(e) For landfills electing to measure the fraction by 

volume of CH4 in landfill gas (F), follow the 

requirements in paragraphs (e)(1) and (e)(2) of this 

section. 

(1) Use a gas composition monitor capable of 

measuring the concentration of CH4 on a dry basis 

that is properly operated, calibrated, and maintained 

according to the requirements specified in paragraph 

(b) of this section. You must either use a gas 

composition monitor that is also capable of 

measuring the O2 concentration correcting for excess 

(infiltration) air or you must operate, maintain, and 

Harmonizing change to accommodate the correction 

to 0 percent oxygen for CH4 content of landfill gas
59

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

calibrate a second monitor capable of measuring the 

O2 concentration on a dry basis according to the 

manufacturer's specifications.

(2) Use Equation HH-10 of this section to correct the 

measured CH4 concentration to 0% oxygen. If 

multiple CH4 concentration measurements are made 

during the reporting year, determine F separately for 

each measurement made during the reporting year, 

and use the results to determine the arithmetic 

average value of F for use in Equation HH–1 of this 

part.

F = (CCH4/100%)x[20.9c/(20.9-%O2)] (Eq. HH10)

Where:

F = Fraction by volume of CH4 in landfill gas 

(fraction, dry basis, corrected to 0 percent oxygen).

CCH4 = Measured CH4 concentration in landfill gas 

(volume percent, dry basis).

20.9c = Defined O2 correction basis, (volume 

percent, dry basis).

20.9 = O2 concentration in air (volume percent, dry 

basis).

%O2 = Measured O2 concentration in landfill gas 

(volume percent, dry basis).

HH 98.344(f) (None) (f) The owner or operator shall document the 

procedures used to ensure the accuracy of the 

estimates of disposal quantities and, if applicable, 

gas flow rate, gas composition, temperature, 

pressure, and moisture content measurements. These 

procedures include, but are not limited to, calibration 

of weighing equipment, fuel flow meters, and other 

measurement devices. The estimated accuracy of 

measurements made with these devices shall also be 

recorded, and the technical basis for these estimates 

shall be provided.

Harmonizing change. Moves paragraph to 

accommodate new paragraph (e)

HH 98.345(c) (c) For missing daily waste disposal quantity data for 

disposal in reporting years, the substitute value 

(c) For missing daily waste disposal quantity data for 

disposal in the reporting year, the substitute value 

See preamble text for explanation
60

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

shall be the average daily waste disposal quantity for 

that day of the week as measured on the week before 

and week after the missing daily data.

shall be the average daily waste disposal quantity for 

that day of the week as measured on the week before 

and week after the missing daily data.

HH 98.346(d)(1) (1) Degradable organic carbon (DOC), methane 

correction factor (MCF), and fraction of DOC 

dissimilated (DOCF) values used in the calculations. 

If an MCF value other than the default of 1 is used, 

provide an indication of whether active aeration of 

the waste in the landfill was conducted during the 

reporting year, a description of the aeration system, 

including aeration blower capacity, the fraction of 

the landfill containing waste affected by the aeration, 

the total number of hours during the year the aeration 

blower was operated, and other factors used as a 

basis for the selected MCF value.

(1) Degradable organic carbon (DOC) and fraction of 

DOC dissimilated (DOCF) values used in the 

calculations.

See preamble text for explanation

HH 98.346(e) (e) Fraction of CH4in landfill gas (F), and an 

indication of whether the fraction of CH4was 

determined based on measured values or the default 

value

(e) Fraction of CH4 in landfill gas (F), an indication 

of whether the fraction of CH4 was determined based 

on measured values or the default value, and the 

methane correction factor (MCF) used in the 

calculations. If an MCF other than the default of 1 is 

used, provide an indication of whether active 

aeration of the waste in the landfill was conducted 

during the reporting year, a description of the 

aeration system, including aeration blower capacity, 

the fraction of the landfill containing waste affected 

by aeration, the total number of hours during the year 

the aeration blower was operated, and other factors 

used as a basis for the selected MCF value.

See preamble for discussion
61

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

HH 98.346(h) (h) For landfills without gas collection systems, the 

annual methane emissions (i.e., the methane 

generation, adjusted for oxidation, calculated using 

Equation HH–5 of this subpart), reported in metric 

tons CH4, and an indication of whether passive 

vents and/or passive flares (vents or flares that are 

not considered part of the gas collection system as 

defined in §98.6) are present at this landfill.

(h) For landfills without gas collection systems, the 

annual methane emissions (i.e., the methane 

generation, adjusted for oxidation, calculated using 

Equation HH–5 of this subpart), reported in metric 

tons CH4, the oxidation fraction used in the 

calculation, and an indication of whether passive 

vents and/or passive flares (vents or flares that are 

not considered part of the gas collection system as 

defined in §98.6) are present at this landfill.

Harmonizes reporting requirements with calculation 

method.

HH 98.346(i)(5) (5) An indication of whether destruction occurs at 

the landfill facility or offsite. If destruction occurs at 

the landfill facility, also report an indication of 

whether a back-up destruction device is present at 

the landfill, the annual operating hours for the 

primary destruction device, the annual operating 

hours for the back-up destruction device (if present), 

and the destruction efficiency used (percent).

(5) An indication of whether destruction occurs at 

the landfill facility, off-site, or both. If destruction 

occurs at the landfill facility, also report for each 

measurement location an indication of whether a 

back-up destruction device is present at the landfill, 

the annual operating hours for the primary 

destruction device, the annual operating hours for the 

back-up destruction device (if present), and the 

destruction efficiency used (percent).

Clarification to provide landfills that use both off-site 

and on-site destruction a clear and accurate reporting 

option.

HH 98.346(i)(8) (8) Methane generation corrected for oxidation 

calculated using Equation HH-5 of this subpart, 

reported in metric tons CH4.

(8) Methane generation corrected for oxidation 

calculated using Equation HH-5 of this subpart, 

reported in metric tons CH4, and the oxidation 

fraction used in the calculation

Harmonizes reporting requirements with calculation 

method.

HH 98.346(i)(10) (8) Methane generation corrected for oxidation 

calculated using Equation HH-7 of this subpart, 

reported in metric tons CH4.

(8) Methane generation corrected for oxidation 

calculated using Equation HH-7 of this subpart, 

reported in metric tons CH4, and the oxidation 

fraction used in the calculation

Harmonizes reporting requirements with calculation 

method.

HH 98.346(i)(11) (8) Methane generation corrected for oxidation 

calculated using Equation HH-6 of this subpart, 

reported in metric tons CH4.

(8) Methane generation corrected for oxidation 

calculated using Equation HH-6 of this subpart, 

reported in metric tons CH4, and the oxidation 

fraction used in the calculation

Harmonizes reporting requirements with calculation 

method.

HH 98.346(i)(12) (8) Methane generation corrected for oxidation 

calculated using Equation HH-8 of this subpart, 

reported in metric tons CH4.

(8) Methane generation corrected for oxidation 

calculated using Equation HH-8 of this subpart, 

reported in metric tons CH4, and the oxidation 

fraction used in the calculation

Harmonizes reporting requirements with calculation 

method.
62

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

HH 98.348 (None) Landfill capacity means the maximum amount of 

solid waste a landfill can accept. For the purposes of 

this subpart, for landfills that have a permit, the 

landfill capacity can be determined in terms of 

volume or mass in the most recent permit issued by 

the state, local, or Tribal agency responsible for 

regulating the landfill, plus any in-place waste not 

accounted for in the most recent permit. If the owner 

or operator chooses to convert from volume to mass 

to determine its capacity, the calculation must 

include a site-specific density.

Add definition to clarify meaning of term as used in 

the rule. 

HH 98.348 (None) Leachate recirculation means the practice of taking 

the leachate collected from the landfill and 

reapplying it to the landfill by any of one of a variety 

of methods, including pre-wetting of the waste, 

direct discharge into the working face, spraying, 

infiltration ponds, vertical injection wells, horizontal 

gravity distribution systems, and pressure 

distribution systems.

Add definition to clarify meaning of term as used in 

the rule. 

HH Table HH-2 Table HH-2 See Appendix A for changes to Table HH-2 Effect changes that were intended to be made in the 

October 28, 2010 (75 FR 66474) amendments and 

revise the last line of this table to read "2009 and all 

later years".

HH Table HH-4 None See Appendix A for Table HH-4 See preamble text for explanation

II 98.353(d)(2) -

Eq. II-6

fDest_1 = Fraction of hours the primary destruction 

device was operating (device operating hours/hours 

in the year). If the biogas is transported off-site for 

destruction, use fDest = 1.

fDest_1 = Fraction of hours the primary destruction 

device was operating calculated as the annual hours 

when the destruction device was operating divided 

by the annual operating hours of the biogas recovery 

system. If the biogas is transported off-site for 

destruction, use fDest = 1.

Clarifies an equation term to more accurately reflect 

operating hours of biogas recovery system.

II 98.353(d)(2) -

Eq. II-6

fDest_2 = Fraction of hours the back-up destruction 

device was operating (device operating hours/hours 

in the year).

fDest_2 = Fraction of hours the back-up destruction 

device was operating calculated as the annual hours 

when the destruction device was operating divided 

by the annual operating hours of the biogas recovery 

system.

Clarifies equation term to more accurately reflect 

operating hours of biogas recovery system.

LL 98.386(a)(1) (1) For each product listed in Table MM-1 of subpart 

MM of this part that enters the coal-to-liquid facility 

to be further processed or otherwise used on site, 

report the annual quantity in metric tons or barrels by 

(1) [Reserved.] See preamble text for explanation
63

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

each quantity measurement standard method or other 

industry standard practice used. For natural gas 

liquids, quantity shall reflect the individual 

components of the product.

LL 98.386(a)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(1) of this section.

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(2) of this section.

Harmonizing change with 40 CFR 98.386(a)(1).

LL 98.386(a)(5) (5) For each product (leaving the coal-to-liquid 

facility) listed in Table MM-1 of subpart MM of this 

part, report the annual quantity in metric tons or 

barrels by each quantity measurement standard 

method or other industry standard practice used. For 

natural gas liquids, quantity shall reflect the 

individual components of the product. Those 

products that enter the facility, but are not reported in 

(a)(1), shall not be reported under this paragraph.

(5) [Reserved.] See preamble text for explanation

LL 98.386(a)(8) (8) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(5) of this section.

(8) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(6) of this section.

Harmonizing change with 40 CFR 98.386(a)(5).

LL 98.386(a)(9)(

v)

(v) The calculated CO2 emissions factor. (v) The calculated CO2 emissions factor in metric 

tons CO2 per barrel or per metric ton of product.

Clarifies units of reporting requirement

LL 98.386(a)(11)

(v)

(v) The calculated CO2 emissions factor. (v) The calculated CO2 emissions factor in metric 

tons CO2 per barrel or per metric ton of product.

Clarifies units of reporting requirement

LL 98.386(a)(13) (13)For each specific type of biomass that enters the 

coal-to-liquid facility to be co-processed with fossil 

fuel-based feedstock to produce a product reported in 

paragraph (a)(6) of this section, report the annual 

quantity in metric tons or barrels by each quantity 

measurement standard method or other industry 

standard practice used.

(13) [Reserved.] See preamble text for explanation

LL 98.386(a)(15) (15) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(3) of this section.

(15) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(14 ) of this section.

Harmonizing change with 40 CFR 98.386(a)(13) and 

corrects reference

LL 98.386(a)(18) (18) Annual CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of 

each type of biomass feedstock co-processed with 

fossil fuel-based feedstocks reported in paragraph 

(a)(3) of this section, calculated according to 

§98.393(c).

(18) Annual CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of 

each type of biomass feedstock co-processed with 

fossil fuel-based feedstocks reported in paragraph 

(a)(14) of this section, calculated according to 

§98.393(c).

Harmonizing change with 40 CFR 98.386(a)(13) and 

corrects reference
64

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

LL 98.386(b)(1) (1) For each product listed in Table MM-1 of subpart 

MM of this part, report the annual quantity in metric 

tons or barrels by each quantity measurement 

standard method or other industry standard practice 

used. For natural gas liquids, quantity shall reflect 

the individual components of the product.

1) [Reserved.] See preamble text for explanation

LL 98.386(b)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (b)(1) of this section.

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (b)(2) of this section.

Harmonizing change with 40 CFR 98.386 (b)(1)

LL 98.386(b)(5)(

v)

(v) The calculated CO2 emissions factor in metric 

tons. 

(v) The calculated CO2 emissions factor in metric 

tons CO2 per barrel or per metric ton of product.

Clarifies units of reporting requirement

LL 98.386( c)(1) (1) For each product listed in Table MM-1 of subpart 

MM of this part, report the annual quantity in metric 

tons or barrels by each quantity measurement 

standard method or other industry standard practice 

used. For natural gas liquids, quantity shall reflect 

the individual components of the product.

(1) [Reserved.] See preamble text for explanation

LL 98.386( c)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (c)(1) of this section

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (c)(2) of this section

Harmonizing change with 40 CFR 98.386 (c)(1)

LL 98.386( 

c)(5)(v)

(v) The calculated CO2 emissions factor in metric 

tons. 

(v) The calculated CO2 emissions factor in metric 

tons CO2 per barrel or per metric ton of product.

Clarifies units of reporting requirement

LL 98.386(d)(2) (2) For a product that enters the facility to be further 

refined or otherwise used on site that is a blended 

feedstock, producers must meet the reporting 

requirements of paragraphs (a)(1) and (a)(2) of this 

section by reflecting the individual components of 

the blended feedstock.

(2) For a product that enters the facility to be further 

refined or otherwise used on site that is a blended 

feedstock, producers must meet the reporting 

requirements of paragraph (a)(2) of this section by 

reflecting the individual components of the blended 

feedstock.

Harmonizing change with 40 CFR 98.386(a)(1).

LL 98.386(d)(3) (3) For a product that is produced, imported, or 

exported that is a blended product, producers, 

importers, and exporters must meet the reporting 

requirements of paragraphs (a)(5), (a)(6), (b)(1), 

(b)(2), (c)(1), and (c)(2) of this section, as applicable, 

by reflecting the individual components of the 

blended product.

(3) For a product that is produced, imported, or 

exported that is a blended product, producers, 

importers, and exporters must meet the reporting 

requirements of paragraphs (a)(6), (b)(2), and (c)(2) 

of this section, as applicable, by reflecting the 

individual components of the blended product.

Harmonizing change with 40 CFR 98.386(a)(1), 

(b)(1), and (c )(1) 

MM 98.393(a)(1) Producti = Annual volume of product "i" produced, 

imported, or exported by the reporting party 

(barrels). For refiners, this volume only includes 

products ex refinery gate, and excludes products that 

Producti = Annual volume of product "i" produced, 

imported, or exported by the reporting party 

(barrels). For refiners, this volume only includes 

products ex refinery gate, and excludes products that 

Updated reference to harmonize with changes to 

98.396(a)(1)
65

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

entered the refinery but are not reported under 

98.396(a)(1). For natural gas liquids, volumes shall 

reflect the individual components of the product as 

listed in Table MM-1 to subpart MM. 

entered the refinery but are not reported under 

98.396(a)(2). For natural gas liquids, volumes shall 

reflect the individual components of the product as 

listed in Table MM-1 to subpart MM. 

MM 98.393(a)(2) Producti = Annual mass of product "i" produced, 

imported, or exported by the reporting party (metric 

tons). For refiners, this mass only includes products 

ex refinery gate. 

Producti = Annual mass of product "i" produced, 

imported, or exported by the reporting party (metric 

tons). For refiners, this mass only includes products 

ex refinery gate, and excludes products that entered 

the refinery but are not reported under §98.396(a)(2).

See preamble text for explanation

MM 98.393(h)(1) (1) A reporter using Calculation Methodology 1 to 

determine the emission factor of a petroleum product 

shall calculate the CO2 emissions associated with 

that product using Equation MM–8 of this section in 

place of Equation MM–1 of this section.

(1) A reporter using Calculation Method 1 to 

determine the emission factor of a petroleum product 

shall calculate the CO2 emissions associated with 

that product using Equation MM–8 of this section in 

place of Equation MM–1 of this section.

Harmonizing change with 98.393(f)(1). 

MM 98.393(h)(2) A refinery using Calculation Methodology 1 of this 

subpart to determine the emission factor of a noncrude petroleum feedstock shall calculate the CO2

emissions associated with that feedstock using 

Equation MM–9 of this section in place of Equation 

MM–2 of this section.

(2) A refinery using Calculation Method 1 of this 

subpart to determine the emission factor of a noncrude petroleum feedstock shall calculate the CO2

emissions associated with that feedstock using 

Equation MM–9 of this section in place of Equation 

MM–2 of this section.

Harmonizing change with 98.393(f)(1).

MM 98.394(a)(1) (1) The quantity of petroleum products, natural gas 

liquids, and biomass, as well as the quantity of crude 

oil measured on site at a refinery, shall be 

determined as follows:

(1) The quantity of petroleum products, natural gas 

liquids, and biomass, shall be determined as follows:

See preamble text for explanation

MM 98.394(a)(3) (3) The quantity of crude oil not measured on site at 

a refinery shall be determined according to one of the 

following methods. You may use an appropriate 

standard method published by a consensus-based 

standards organization or you may use an industry 

standard practice.

(3) The annual quantity of crude oil received shall be 

determined according to one of the following 

methods. You may use an appropriate standard 

method published by a consensus-based standards 

organization or you may use an industry standard 

practice.

See preamble text for explanation
66

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

MM 98.394(b) (None) (3) For units and processes that operate continuously 

with infrequent outages, it may not be possible to 

complete the calibration of a flow meter or other 

measurement device without disrupting normal 

process operation. In such cases, the owner or 

operator may postpone the calibration until the next 

scheduled maintenance outage. The best available 

information from company records may be used in 

the interim. Such postponements shall be 

documented in the monitoring plan that is required 

under §98.3(g)(5).

See preamble text for explanation

MM 98.394(c) (c) Procedures for Calculation Methodology 2 of this 

subpart.

(c) Procedures for Calculation Method 2 of this 

subpart.

Harmonizing change with 98.393(f)(2).

MM 98.394(d) (d) Measurement of API gravity and sulfur content 

of crude oil

(4) [Reserved] See preamble text for explanation

MM 98.395(a)

(a) Determination of quantity. Whenever the quality 

assurance procedures in §98.394(a) cannot be 

followed to measure the quantity of one or more 

petroleum products, natural gas liquids, types of 

biomass, feedstocks, or crude oil batches during any 

period (e.g., if a meter malfunctions), the following 

missing data procedures shall be used:

(a) Determination of quantity. Whenever the quality 

assurance procedures in §98.394(a) cannot be 

followed to measure the quantity of one or more 

petroleum products, natural gas liquids, types of 

biomass, feedstocks, or crude oil during any period 

(e.g., if a meter malfunctions), the following missing 

data procedures shall be used:

See preamble text for explanation

MM 98.395(b) (b) Determination of emission factor. Whenever any

of the procedures in §98.394(c) cannot be followed 

to develop an emission factor for any reason, 

Calculation Methodology 1 of this subpart must be 

used in place of Calculation Methodology 2 of this 

subpart for the entire reporting year.

(b) Determination of emission factor. Whenever any 

of the procedures in §98.394(c) cannot be followed 

to develop an emission factor for any reason, 

Calculation Method 1 of this subpart must be used in 

place of Calculation Method 2 of this subpart for the 

entire reporting year.

Clarifies method

MM 98.395(c ) (c) Determination of API gravity and sulfur content 

of crude oil. For missing data on sulfur content or 

(c ) [Reserved] See preamble text for explanation
67

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

API gravity, the substitute data value shall be the 

arithmetic average of the quality-assured values of 

API gravity or sulfur content in the batch preceding 

and the batch immediately following the missing 

data incident. If no quality-assured data are available 

prior to the missing data incident, the substitute data 

value shall be the first quality-assured values for API

gravity and sulfur content obtained from the batch 

after the missing data period.

MM 98.396(a)(1) (1) For each petroleum product or natural gas liquid 

listed in table MM–1 of this subpart that enters the 

refinery to be further refined or otherwise used on 

site, report the annual quantity in metric tons or 

barrels by each quantity measurement standard 

method or other industry standard practice used. For 

natural gas liquids, quantity shall reflect the 

individual components of the product.

(1) [Reserved] See preamble text for explanation

MM 98.396(a)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(1) of this section.

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(2) of this section.

Harmonizing change with 40 CFR 98.396(a)(1).

MM 98.396(a)(5) (5) For each petroleum product and natural gas liquid 

(ex refinery gate) listed in Table MM–1 of this 

subpart, report the annual quantity in metric tons or 

barrels by each quantity measurement standard 

method or other industry standard practice used. For 

natural gas liquids, quantity shall reflect the 

individual components of the product. Petroleum 

products and natural gas liquids that enter the 

refinery, but are not reported in (a)(1), shall not be 

reported under this paragraph.

(5) [Reserved] See preamble text for explanation

MM 98.396(a)(8) (8) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(5) of this section.

(8) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(6) of this section.

Harmonizing change with 40 CFR 98.396(a)(5).

MM 98.396(a)(9) (9) For every feedstock reported in paragraph (a)(2) 

of this section for which Calculation Methodology 2 

of this subpart was used to determine an emissions 

factor, report:

(9) For every feedstock reported in paragraph (a)(2) 

of this section for which Calculation Method 2 of 

this subpart was used to determine an emissions 

factor, report:

Corrects terminology

MM 98.396(a)(9)(i (iii) The carbon share test results in percentmass (iii) The carbon share test results in percent mass Corrects typographical error
68

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

ii)

MM 98.396(a)(9)(

v)

(v) The calculated CO2 emissions factor in metric 

tons.

(v) The calculated CO2 emissions factor in metric 

tons CO2 per barrel or per metric ton of product.

Clarifies units of reporting requirement

MM 98.396(a)(10) (10) For every non-solid feedstock reported in 

paragraph (a)(2) of this section for which Calculation 

Methodology 2 of this subpart was used to determine 

an emissions factor, report:

(10) For every non-solid feedstock reported in 

paragraph (a)(2) of this section for which Calculation 

Method 2 of this subpart was used to determine an 

emissions factor, report:

Clarifies method

MM 98.396(a)(11) (11) For every petroleum product and natural gas 

liquid reported in paragraph (a)(6) of this section for 

which Calculation Methodology2 of this subpart was 

used to determine an emissions factor, report:

(11) For every petroleum product and natural gas 

liquid reported in paragraph (a)(6) of this section for 

which Calculation Method 2 of this subpart was used 

to determine an emissions factor, report:

Clarifies method

MM 98.396(11)(iii

)

(iii) The carbon share test results in percentmass. (iii) The carbon share test results in percent mass. Corrects typo

MM 98.396(a)(13) (13) For each specific type of biomass that enters the 

refinery to be co-processed with petroleum 

feedstocks to produce a petroleum product reported 

in paragraph (a)(6) of this section, report the annual 

quantity in metric tons or barrels by each quantity 

measurement standard method or other industry 

standard practice used.

(13) [Reserved] See preamble text for explanation

MM 98.396(a)(15) (15) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(13) of this section.

(15) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (a)(14) of this section.

Harmonizing change with 40 CFR 98.396(a)(13)

MM 98.396(a)(18) (18) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of 

each type of biomass feedstock co-processed with 

petroleum feedstocks reported in paragraph (a)(13) 

of this section, calculated according to §98.393(c).

(18) The CO2 emissions in metric tons that would 

result from the complete combustion or oxidation of 

each type of biomass feedstock co-processed with 

petroleum feedstocks reported in paragraph (a)(14) 

of this section, calculated according to §98.393(c).

Harmonizing change with 40 CFR 98.396(a)(13)

MM 98.396(a)(20) (20) All of the following information for all crude oil 

feedstocks used at the refinery:

(i) Batch volume in barrels.

(ii) Weighted average API gravity representing the 

batch at the point of entry at the refinery.

(iii) Weighted average sulfur content representing 

the batch at the point of entry at the refinery.

(iv) Country of origin, of the batch, if known and 

data in paragraphs (a)(20)(v) and (a)(20)(vi) of this 

section are unknown.

(20) For all crude oil that enters the refinery, report 

the annual quantity in barrels. 

See preamble text for explanation
69

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

(v) EIA crude stream code and crude stream name of 

the batch, if known.

(vi) Generic name for the crude stream and the 

appropriate EIA two-letter country or state and 

production area code of the batch, if known and no 

appropriate EIA crude stream code exists.

MM 98.396(a)(21) (21) The quantity of bulk NGLs in metric tons or 

barrels received for processing during the reporting 

year. 

(21) The quantity of bulk NGLs in metric tons or 

barrels received for processing during the reporting 

year. Report only quantities of bulk NGLs not 

reported in (a)(2) of this section. 

See preamble text for explanation

MM 98.396(a)(22) (22) Volume of crude oil in barrels that you injected 

into a crude oil supply or reservoir. A volume of 

crude oil that entered the refinery, but was not 

reported in paragraphs (a)(2) or (a)(20), shall not be 

reported under this paragraph.

(22) Volume of crude oil in barrels that you injected 

into a crude oil supply or reservoir.

See preamble text for explanation

MM 98.396(a)(23) (23) Special provisions for 2010. For reporting year 

2010 only, a refiner that knows the information 

under a specific tier of the batch definition in 40 

CFR 98.398, but does not have the necessary data 

collection and management in place to readily report 

this information, can use the next most appropriate 

tier of the batch definition for reporting batch 

information under paragraph 98.396(a)(20).

(23) [Reserved] Special provisions for 2010 are no longer necessary.

MM 98.396(b)(1) (1) For each petroleum product and natural gas liquid 

listed in Table MM–1 of this subpart, report the 

annual quantity in metric tons or barrels by each 

quantity measurement standard method or other 

industry standard practice used. For natural gas 

liquids, quantity shall reflect the individual 

components of the product.

(1) [Reserved] See preamble text for explanation

MM 98.396(b)(2) (2) For each petroleum product and natural gas liquid 

listed in Table MM–1 of this subpart, report the 

annual quantity in metric tons or barrels. For natural 

gas liquids, quantity shall reflect the individual 

components of the product as listed in Table MM–1 

of this subpart.

(2) For each petroleum product and natural gas liquid 

listed in Table MM–1 of this subpart, report the 

annual quantity in metric tons or barrels. For natural 

gas liquids, quantity shall reflect the individual 

components of the product.

Clarifies reporting requirements. Reporting is not 

limited to those components listed in Table MM-1.
70

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

MM 98.396(b)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (b)(1) of this section.

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (b)(2) of this section.

Harmonizing change with 40 CFR 98.396 (b)(1)

MM 98.396(b)(5) (5) For each product reported in paragraph (b)(2) of 

this section for which Calculation Methodology 2 of 

this subpart used was used to determine an emissions 

factor, report:

(5) For each product reported in paragraph (b)(2) of 

this section for which Calculation Method 2 of this 

subpart used was used to determine an emissions 

factor, report:

Clarifies method

MM 98.396(b)(6) (6) For each non-solid product reported in paragraph 

(b)(2) of this section for which Calculation 

Methodology 2 of this subpart was used to determine 

an emissions factor, report:

(6) For each non-solid product reported in paragraph 

(b)(2) of this section for which Calculation Method 2 

of this subpart was used to determine an emissions 

factor, report:

Clarifies method

MM 98.396( c)(1) (1) For each petroleum product and natural gas liquid 

listed in Table MM–1 of this subpart, report the 

annual quantity in metric tons or barrels by each 

quantity measurement standard method or other 

industry standard practice used. For natural gas 

liquids, quantity shall reflect the individual 

components of the product.

(1)[Reserved] See preamble text for explanation

MM 98.396( c)(4) (4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (c)(1) of this section.

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in 

paragraph (c)(2) of this section.

Harmonizing change with 40 CFR 98.396 (c)(1)

MM 98.396(c)(5) (5) For each product reported in paragraph (c)(2) of 

this section for which Calculation Methodology 2 of 

this subpart was used to determine an emissions 

factor, report:

(5) For each product reported in paragraph (c)(2) of 

this section for which Calculation Method 2 of this 

subpart was used to determine an emissions factor, 

report:

Clarifies method

MM 98.396(c)(6) (6) For each non-solid product reported in paragraph 

(c)(2) of this section for which Calculation 

Methodology 2 of this subpart used was used to 

determine an emissions factor, report:

(6) For each non-solid product reported in paragraph 

(c)(2) of this section for which Calculation Method 2 

of this subpart used was used to determine an 

emissions factor, report:

Clarifies method

MM 98.396(d)(2) (2) For a product that enters the refinery to be further 

refined or otherwise used on site that is a blended 

non-crude feedstock, refiners must meet the 

reporting requirements of paragraphs (a)(1) and 

(a)(2) of this section by reflecting the individual 

components of the blended non-crude feedstock.

(2) For a product that enters the refinery to be further 

refined or otherwise used on site that is a blended 

non-crude feedstock, refiners must meet the 

reporting requirements of paragraphs (a)(2) of this 

section by reflecting the individual components of 

the blended non-crude feedstock.

Harmonizing change with 40 CFR 98.396 (a)(1)

MM 98.396(d)(3) (3) For a product that is produced, imported, or (3) For a product that is produced, imported, or Harmonizing change with 40 CFR 98.396 (a)(1), 
71

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

exported that is a blended product, refiners, 

importers, and exporters must meet the reporting 

requirements of paragraphs (a)(5), (a)(6), (b)(1), 

(b)(2), (c)(1), and (c)(2) of this section, as applicable, 

by reflecting the individual components of the 

blended product.

exported that is a blended product, refiners, 

importers, and exporters must meet the reporting 

requirements of paragraphs (a)(6), (b)(2), and (c)(2) 

of this section, as applicable, by reflecting the 

individual components of the blended product.

(b)(1), and (c )(1)

MM 98.397(b) (b) Reporters shall maintain records to support 

quantities that are reported under this subpart, 

including records documenting any estimations of 

missing data and the number of calendar days in the 

reporting year for which substitute data procedures 

were followed. For all reported quantities of 

petroleum products, natural gas liquids, and biomass, 

as well as crude oil quantities measured on site at a 

refinery, reporters shall maintain metering, gauging, 

and other records normally maintained in the course 

of business to document product and feedstock flows 

including the date of initial calibration and the 

frequency of recalibration for the measurement 

equipment used.

(b) Reporters shall maintain records to support 

quantities that are reported under this subpart, 

including records documenting any estimations of 

missing data and the number of calendar days in the 

reporting year for which substitute data procedures 

were followed. For all reported quantities of 

petroleum products, natural gas liquids, and biomass, 

reporters shall maintain metering, gauging, and other 

records normally maintained in the course of 

business to document product and feedstock flows 

including the date of initial calibration and the 

frequency of recalibration for the measurement 

equipment used.

Harmonizing change with 40 CFR 98.396(a)(20). 

MM 98.397(d) (d) Reporters shall maintain laboratory reports, 

calculations and worksheets used in the measurement 

of density and carbon share for any petroleum 

product or natural gas liquid for which CO2 

emissions were calculated using Calculation 

Methodology 2.

(d) Reporters shall maintain laboratory reports, 

calculations and worksheets used in the measurement 

of density and carbon share for any petroleum 

product or natural gas liquid for which CO2 

emissions were calculated using Calculation Method

2.

Clarifies method

MM 98.398 (None) Bulk NGLs for purposes of reporting under this 

subpart means mixtures of NGLs that are sold or 

delivered as undifferentiated product.

See preamble text for explanation

MM 98.398 (None) Natural Gas Liquids (NGLs) for the purposes of 

reporting under this subpart means hydrocarbons that 

are separated from natural gas as liquids through the 

process of absorption, condensation, adsorption, or 

other methods, and are sold or delivered as 

differentiated product. Generally, such liquids 

consist of ethane, propane, butanes, or pentanes plus.

See preamble text for explanation
72

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

MM 98.398 Batch means either a volume of crude oil that enters 

a refinery or the components of such volume (e.g., 

the volumes of different crude streams that are 

blended together and then delivered to a refinery). 

The batch volume is the first appropriate tier in the 

following list:

(1) Up to an annual volume of a type of crude oil 

identified by an EIA crude stream code, if the EIA 

crude stream code is known.

(2) Up to an annual volume of a type of crude oil 

identified by a generic name for the crude stream and 

an appropriate EIA two-letter country or state and 

production area code, if the generic name and EIA 

two-letter code are known but no appropriate EIA 

crude stream code exists.

(3) Up to a calendar month of crude oil volume from 

a single known foreign country of origin if the crude 

stream name is unknown.

(4) Up to a calendar month of crude oil volume from 

the United States if the crude stream name and 

production area are unknown.

(5) Up to a calendar month of crude oil volume if the 

country of origin is unknown.

(None)

MM Table MM-1 Table MM-1 See Appendix A for changes to Table MM-1 See preamble text for explanation

NN 98.400(a) (a) Natural gas liquids fractionators are installations 

that fractionate natural gas liquids (NGLs) into their 

consitutent liquid products (ethane, propane, normal 

butane, isobutane or pentanes plus) for supply to 

downstream facilities.

(a) Natural gas liquids fractionators are installations 

that fractionate natural gas liquids (NGLs) into their 

constituent liquid products or mixtures of products 

(ethane, propane, normal butane, isobutane or 

pentanes plus) for supply to downstream facilities.

Clarifies rule text.

NN 98.400(b) (b) Local Distribution Companies (LDCs) are 

companies that own or operate distribution pipelines, 

not interstate pipelines or intrastate pipelines, that 

physically deliver natural gas to end users and that 

are regulated as separate operating companies by 

State public utility commissions or that operate as 

independent municipally-owned distribution 

systems.

(b) Local Distribution Companies (LDCs) are 

companies that own or operate distribution pipelines, 

not interstate pipelines or intrastate pipelines, that 

physically deliver natural gas to end users and that 

are within a single state that are regulated as separate 

operating companies by State public utility 

commissions or that operate as independent 

municipally-owned distribution systems. LDCs do 

not include pipelines (both interstate and intrastate) 

delivering natural gas directly to major industrial 

See preamble text for explanation
73

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

users and farm taps upstream of the local distribution 

company inlet.

NN 98.403(a)(2) Fuelh = Total annual volume of product ―h‖ supplied 

(bbl or Mscf per year)

Fuelh = Total annual volume of product ―h‖ supplied 

(volume per year, in Mscf for natural gas and bbl for 

NGLs).

Clarifies equation term.

NN 98.403(b) (1) (1) For natural gas that is received for redelivery to 

downstream gas transmission pipelines and other 

local distribution companies, use eEquation NN–3 of 

this section and the default values for the CO2

emission factors found in Table NN–2 of this 

subpart.***

(1) For natural gas that is received for redelivery to 

downstream gas transmission pipelines and other 

local distribution companies, use Equation NN–3 of 

this section and the default values for the CO2 

emission factors found in Table NN–2 of this 

subpart.***.

Corrects typographical error

NN 98.403(b)(2)(

i)

(2)(i) For natural gas delivered to each meter 

registering a supply equal to or greater than 460,000 

Mscf per year, use Equation NN–4 of this section 

and the default values for the CO2 emission factors 

found in Table NN–2 of this subpart.

(2)(i) For natural gas delivered to end-users 

registering a supply equal to or greater than 460,000 

Mscf per year, use Equation NN–4 of this section 

and the default values for the CO2 emission factors 

found in Table NN–2 of this subpart.

See preamble text for explanation

NN 98.403(b)(2)(

ii)

CO2k = Annual CO2 mass emissions that would 

result from the combustion or oxidation of natural 

gas received by end-users that receive a supply equal 

to or greater than 460,000 Mscf per year (metric 

tons).

CO2k = Annual CO2 mass emissions that would 

result from the combustion or oxidation of natural 

gas delivered to each end-user that receives a supply 

equal to or greater than 460,000 Mscf per year 

(metric tons).

Clarifies rule text.

NN 98.403(b)(2)(

ii)

Fuel = Total annual volume of natural gas supplied 

(Mscf per year).

Fuel = Total annual volume of natural gas supplied 

to this end-user, if known, otherwise, the annual 

volume supplied to this meter (Mscf per year).

Clarifies the definition of the equation term ―Fuel‖ in 

Equation NN-4‖ . The input for the total annual 

volume of natural gas must be the total annual 

volume of natural gas supplied to the end-user, if 

known.

NN 98.403(b)(3) (3) For natural gas received by the LDC at the city 

gate that is injected into on-system storage, and/or 

liquefied and stored, use Equation NN–5 of this 

section and the default value for the CO2 emission 

factors found in Table NN–2 of this subpart. 

Alternatively, a reporter-specific CO2 emission 

factor may be used, provided it is developed using 

methods outlined in §98.404.

CO2l = [Fuel1-Fuel2]*EF (Eq. NN-5)

Where:

CO2l = Annual CO2 mass emissions that would result 

from the combustion or oxidation of the net natural 

gas that is liquefied and/or stored and not used for 

(3) For the net change in natural gas stored on 

system by the LDC during the reporting year, use 

Equation NN-5a of this section. For natural gas that 

is received by means other than through the city gate, 

and is not otherwise accounted for by Equation NN-1 

or NN-2 of this section, use Equation NN-5b of this 

section.

(i) For natural gas received by the LDC that is 

injected into on-system storage, and/or liquefied and 

stored, and for gas removed from storage and used 

for deliveries, use Equation NN–5a of this section 

and the default value for the CO2 emission factors 

found in Table NN–2 of this subpart. Alternatively, a 

Harmonize with changes to equations - see preamble 

rationale for a complete explanation of the changes.
74

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

deliveries by the LDC within the reported year 

(metric tons).

Fuel1 = Total annual volume of natural gas received 

by the LDC at the city gate and stored on-system or 

liquefied and stored in the reporting year (Mscf per 

year).

Fuel2 = Total annual volume of natural gas that is 

used for deliveries in the reporting year that was not 

otherwise accounted for in Equation NN–1 or NN–2 

of this section (Mscf per year). This primarily 

includes natural gas previously stored on-system or 

liquefied and stored that is removed from storage and 

used for deliveries to customers or other LDCs by 

the LDC within the reporting year. This also includes 

natural gas that bypassed the city gate and was 

delivered directly to LDC systems from producers or 

natural gas processing plants from local production. 

EF = Fuel-specific CO2 emission factor (MT 

CO2/Mscf).

reporter-specific CO2 emission factor may be used, 

provided it is developed using methods outlined in 

§98.404.

CO2l = [Fuel1-Fuel2]*EF (Eq. NN-5a)

Where:

CO2l = Annual CO2 mass emissions that would result 

from the combustion or oxidation of the net change 

in natural gas stored on system by the LDC within 

the reporting year (metric tons).

Fuel1 = Total annual volume of natural gas added to 

storage on-system or liquefied and stored in the 

reporting year (Mscf per year).

Fuel2 = Total annual volume of natural gas that is 

removed from storage or vaporized and removed 

from storage and used for deliveries to customers or 

other LDCs by the LDC within the reporting year 

(Mscf per year).

EF = Annual average CO2 emission factor for natural 

gas placed into/removed from storage(MT 

CO2/Mscf).

NN 98.403(b)(3)(

ii)

(None) (ii)(ii) For natural gas received by the LDC that 

bypassed the city gate, use Equation NN-5b of this 

section. This includes natural gas received directly 

by LDC systems from producers or natural gas 

processing plants from local production, received as 

a liquid and vaporized for delivery, or received from 

any other source that bypassed the city gate. Use the 

default value for the CO2 emission factors found in 

Table NN–2 of this subpart. Alternatively, a reporterspecific CO2 emission factor may be used, provided 

it is developed using methods outlined in §98.404.

CO2n = Fuelz * EFz 

Where:

CO2n = Annual CO2 mass emissions that would 

result from the combustion or oxidation of natural 

gas received that bypassed the city gate and is not 

otherwise accounted for by Equation NN-1 or NN-2 

of this section (metric tons).

Fuelz = Total annual volume of natural gas received 

Harmonize with changes to equations - see preamble 

rationale for a complete description of the changes.
75

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

that was not otherwise accounted for by Equation 

NN-1 or NN-2 of this section (natural gas from 

producers and natural gas processing plants from 

local production, or natural gas that was received as 

a liquid, vaporized and delivered, and any other 

source that bypassed the city gate) (Mscf per year). 

EFz = Fuel-specific CO2 emission factor (MT 

CO2/Mscf). 

NN 98.403(b)(4) (4) Calculate the total CO2 emissions that would 

result from the complete combustion or oxidation of 

the annual supply of natural gas to end-users using 

Equation NN–6 of this section.

CO2 = Sum(CO2i)-Sum(CO2j)-Sum(CO2k)-

Sum(CO2l)

Where:

CO2 = Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural gas 

delivered to LDC customers not covered in 

paragraph (b)(2) of this section (metric tons).

CO2i =Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural gas 

delivered to transmission pipelines or other LDCs as 

calculated in paragraph (b)(1) of this section (metric 

tons).

CO2j = Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural gas 

delivered to transmission pipelines or other LDCs as 

calculated in paragraph (b)(1) of this section (metric 

tons).

CO2k = Annual CO2 mass emissions that would 

result from the combustion or oxidation of natural 

gas received by end-users that receive a supply equal 

to or greater than 460,000 Mscf per year as 

calculated in paragraph (b)(2) of this section (metric 

tons).

CO2l = Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural gas 

received by the LDC and liquefied and/or stored but 

not used for deliveries within the reported year as 

(4) Calculate the total CO2 emissions that would 

result from the complete combustion or oxidation of 

the annual supply of natural gas to end-users that 

receive a supply less than 460,000 Mscf per year 

using Equation NN–6 of this section.

CO2 = CO2i+CO2n-CO2j-∑CO2k-CO2l (Eq. NN-6)

Where

CO2 = Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural gas 

delivered to LDC end-users not covered in paragraph 

(b)(2) of this section (metric tons).

CO2i = Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural gas 

received at the city gate as calculated in paragraph 

(a)(1) or (a)(2) of this section (metric tons).

CO2j = Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural gas 

delivered to transmission pipelines or other LDCs as 

calculated in paragraph (b)(1) of this section (metric 

tons).

CO2k = Annual CO2 mass emissions that would 

result from the combustion or oxidation of natural 

gas delivered to each end-user that receives a supply 

equal to or greater than 460,000 Mscf per year as 

calculated in paragraph (b)(2) of this section (metric 

tons).

CO2l = Annual CO2 mass emissions that would result 

from the combustion or oxidation of the net change 

in natural gas stored by the LDC within the reported 

year as calculated in paragraph (b)(3)(i) of this 

section (metric tons).

Harmonize with changes to equations - see preamble 

rationale for a complete explanation
76

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

calculated in paragraph (b)(3) of this section (metric 

tons).

CO2n = Annual CO2 mass emissions that would 

result from the combustion or oxidation of natural 

gas that was received by the LDC directly from 

sources bypassing the city gate, and is not otherwise 

accounted for in Equation NN-1 or NN-2 of this 

section, as calculated in paragraph (b)(3)(ii) of this 

section (metric tons).

NN 98.403( c)(2) (2) Calculate the total CO2 equivalent emissions that 

would result from the combustion or oxidation of 

fractionated NGLs supplied less the quantity 

received by other fractionators using Equation NN-8 

of this section. 

(2) Calculate the total CO2 equivalent emissions that 

would result from the combustion or oxidation of 

fractionated NGLs supplied less the quantity 

received from other fractionators using Equation 

NN-8 of this section. 

Clarifies rule language

NN 98.403( c)(2) CO2 = Annual CO2 mass emissions that would result 

from the combustion or oxidation of fractionated 

NGLs delivered to customers or on behalf of 

customers (metric tons).

CO2 = Annual CO2 mass emissions that would result 

from the combustion or oxidation of fractionated 

NGLs delivered to customers or on behalf of 

customers less the quantity received from other 

fractionators (metric tons).

Clarifies calculation result

NN 98.404(a)(5) (5) For an LDC using Equation NN–1 or NN–2 of 

this subpart, the point(s) of measurement for the 

natural gas volume supplied shall be the LDC city 

gate meter(s).

(5) For an LDC using Equation NN–1 or NN–2 of 

this subpart, the point(s) of measurement for the 

natural gas volume received shall be the LDC city 

gate meter(s).

Clarifies rule language

NN 98.404(a)(7) (7) An LDC using Equation NN–4 of this subpart 

shall measure natural gas at the customer meters. The 

reporter shall consider the volume delivered through 

a single particluar meter at a single particular 

location as the volume delivered to an individual 

end-user.

(7) An LDC using Equation NN–4 of this subpart 

shall measure natural gas at the end-user’s meter(s). 

Where an end-user is known to have more than one 

meter located at their facility, the reporter shall 

measure the natural gas at each meter and sum the 

annual volume delivered to all meters located at the 

end-user’s facility to determine the total volume 

delivered to the end- user. Otherwise, the reporter 

shall consider the total annual volume delivered 

through each single meter at a single particular 

location to be the the volume delivered to an 

individual end-user.

Clarifies rule text.

NN 98.404(a)(8) (8) An LDC using Equation NN–5 of this subpart 

shall measure natural gas as follows:

(i) Fuel1 shall be measured at the on-system storage 

injection meters and/or at the meters measuring 

natural gas to be liquefied.

(8) An LDC using Equation NN–5a and/or NN-5b of 

this subpart shall measure natural gas as follows:

(i) Fuel1 shall be measured at the on-system storage 

injection meters and/or at the meters measuring 

natural gas to be liquefied.

Harmonize with changes to equations - see preamble 

rationale for a complete explanation
77

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

(ii) Fuel2 shall be measured at the meters used for 

measuring on-system storage withdrawals and/or 

LNG vaporization injection. If Fuel2 is from a source 

other than storage, the appropriate meter shall be 

used to measure the quantity.

(ii) Fuel2 shall be measured at the meters used for 

measuring on-system storage withdrawals and/or 

LNG vaporization injection. 

(iii) Fuelz shall be measured using established 

business practices.

NN 98.404(a)(9) (9) An LDC shall measure all natural gas under the 

following standard industry temperature and pressure 

conditions: Cubic foot of gas at a temperature of 60 

degrees Fahrenheit and at an absolute pressure of 

fourteen and seventy-three hundredths (14.73) 

pounds per square inch.

(9) An LDC shall measure all natural gas under the 

following standard industry temperature and pressure 

conditions: Cubic foot of gas at a temperature of 60 

degrees Fahrenheit and at an absolute pressure of one 

atmosphere.

Clarified standard conditions for measurements.

NN 98.404(c )(2) (2) When a reporter used the default EF provided in 

this section to calculate Equation NN–2, NN–3, NN–

4, NN–5, or NN–7 of this subpart, the appropriate 

value shall be taken from Table NN–2 of this 

subpart.

(2) When a reporter used the default EF provided in 

this section to calculate Equation NN-2, NN-3, NN4, NN-5a, NN-5b, or NN-7 of this subpart, the 

appropriate value shall be taken from Table NN-2 of 

this subpart.

Harmonize with changes to equations - see preamble 

rationale for a complete explanation

NN 98.404(d)(1) (1) Equipment used to measure quantities in 

Equations NN–1, NN–2, and NN–5 of this subpart 

shall be calibrated prior to its first use for reporting 

under this subpart, using a suitable standard method 

published by a consensus based standards 

organization or according to the equipment 

manufacturer's directions.

(1) Equipment used to measure quantities in 

Equations NN–1, NN–2, NN–5a and NN-5b of this 

subpart shall be calibrated prior to its first use for 

reporting under this subpart, using a suitable 

standard method published by a consensus based 

standards organization or according to the equipment 

manufacturer's directions.

Harmonize with changes to equations - see preamble 

rationale for a complete explanation

NN 98.404(d)(2) (2) Equipment used to measure quantities in 

Equations NN–1, NN–2, and NN–5 of this subpart 

shall be recalibrated at the frequency specified by the 

standard method used or by the manufacturer's 

directions.

(2) Equipment used to measure quantities in 

Equations NN–1, NN–2, NN–5a, and NN-5b of this 

subpart shall be recalibrated at the frequency 

specified by the standard method used or by the 

manufacturer's directions.

Harmonize with changes to equations - see preamble 

rationale for a complete explanation

NN 98.404(d)(3) [(None)] (3) Equipment used to measure quantities in 

Equations NN-3, and NN-4 of this subpart shall be 

recalibrated at the frequency commonly used within 

the industry. 

Clarification of when to calibrate equipment made in 

case of new reporters

NN 98.404(a)(5) 5) For an LDC using Equation NN–1 or NN–2 of 

this subpart, the point(s) of measurement for the 

natural gas volume supplied shall be the LDC city 

gate meter(s).

5) For an LDC using Equation NN–1 or NN–2 of 

this subpart, the point(s) of measurement for the 

natural gas volume received shall be the LDC city 

gate meter(s).

Clarifies rule text. 

NN 98.405( c)(3) (3) Whenever a NGL fractionator cannot follow the 

quality assurance procedures for developing a 

reporter-specific HHV, as specified in §98.404, 

(3) [Reserved] Deleted duplicate requirement
78

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

during any period for any reason, the NGL 

fractionator shall use the default HHV provided in 

Table NN–1 of this part for that period.

NN 98.406(a)(4) (4) Annual quantity (in barrels) of y-grade, bulk 

NGLs received from others for fractionation.

(4) Annual quantities (in barrels) of y-grade, o-grade, 

and other bulk NGLs:

(i) received.

(ii) Supplied to downstream users that are not 

fractionated by the reporter.

See preamble text for explanation

NN 98.406(a)(7) (7) Annual CO2 mass emissions (metric tons) that 

would result from the combustion or oxidation of 

fractionated NGLs supplied less the quantity 

received by other fractionators, calculated in 

accordance with §98.403(c)(2).

(7) Annual CO2 mass emissions (metric tons) that 

would result from the combustion or oxidation of 

fractionated NGLs supplied less the quantity 

received from other fractionators, calculated in 

accordance with §98.403(c)(2). If the calculated 

value is negative, the reporter shall report the value 

as zero.

Corrects regulatory text and resolves potential for 

negative calculation result due to rounding of 

emission factors.

NN 98.406(b)(2) (2) Annual volume in Mscf of natural gas placed into 

storage.

(2) Annual volume in Mscf of natural gas placed 

into storage or liquified and stored (Fuel 1 in 

Equation NN-5a).

Includes equation terms for clarity - see preamble 

rationale line 147.

NN 98.406(b)(3) (3) Annual volume in Mscf of vaporized liquefied 

natural gas (LNG) produced at on-system 

vaporization facilities for delivery on the distribution 

system that is not accounted for in paragraph (b)(1) 

of this section.

(3) Annual volume in Mscf of natural gas withdrawn 

from on-system storage and annual volume in Mscf 

of vaporized liquefied natural gas (LNG) produced at 

on-system vaporization facilities withdrawn from 

storage for delivery on the distribution system (Fuel2

in Equation NN-5a). 

Harmonize reporting requirements with calculation 

changes - see preamble rationale for a complete 

explanation

NN 98.406(b)(4) (4) Annual volume in Mscf of natural gas withdrawn 

from on-system storage (that is not delivered to the 

city gate) for delivery on the distribution system.

(4) [Reserved] Reporting of revised definition Fuel 2 in 

98.406(b)(3) eliminates the need for this reporting 

element. 

NN 98.406(b)(5) (5) Annual volume in Mscf of natural gas delivered 

directly to LDC systems from producers or natural 

gas processing plants from local production.

(5) Annual volume in Mscf of natural gas that 

bypassed the city gate(s) and was supplied through 

the LDC distribution system. This includes natural 

gas from producers and natural gas processing plants 

from local production, or natural gas that was 

vaporized upon receipt and delivered, and any other 

source that bypassed the city gate (Fuelz in Equation 

NN-5b).

Harmonize reporting requirements with calculation 

changes - see preamble rationale for a complete 

explanation

NN 98.406(b)(7) (7) Annual volume in Mscf of natural gas delivered 

by LDC to each meter registering supply equal to or 

greater than 460,000 Mcsf during the calendar year.

(7) Annual volume in Mscf of natural gas delivered 

by the LDC to each end-user facility that received 

from the LDC deliveries equal to or greater than 

460,000 Mscf during the calendar year, if known; 

See preamble text for explanation
79

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

otherwise, report the annual volume in Mscf of 

natural gas delivered by the LDC to each meter 

registering supply equal to or greater than 460,000 

Mscf during the calendar year.

NN 98.406(b)(9) (9) Annual CO2 emissions (metric tons) that would 

result from the complete combustion or oxidation of 

the annual supply of natural gas to end-users 

registering less than 460,000 Mcsf, calculated in 

accordance with §98.403(b)(4).

(9) Annual CO2 emissions (metric tons) that would 

result from the complete combustion or oxidation of 

the annual supply of natural gas to end-users 

registering less than 460,000 Mscf, calculated in 

accordance with §98.403(b)(4). If the calculated 

value is negative, the reporter shall report the value 

as zero.

Corrects typographical error, and resolves potential 

for negative calculation result due to rounding of 

emission factors. 

NN 98.406(b)(12) (12) The customer name, address, and meter number 

of each meter reading used to report in paragraph 

(b)(7) of this section.

(12) The customer name, address, and meter number 

of each end-user reported in paragraph (b)(7) of this 

section. Additionally, report whether the quantity of 

natural gas reported in paragraph (b)(7) of this 

section is the total quantity delivered to the end-user, 

or the quantity delivered to a specific meter.

Clarifies rule text.

NN 98.407

Introductory 

Paragraph

98.407 Records that must be retained. 

In addition to the information required by §98.3(g), 

each annual report must contain the following 

information:

98.407 Records that must be retained. 

In addition to the information required by §98.3(g), 

the reporter shall retain the following records:

Corrects requirement.

NN 98.408 -

Table NN-1

Table NN–1 to Subpart HH of Part 98—Default 

Factors for Calculation Methodology 1 of This 

Subpart

See Appendix A for changes to Table NN-1 Corrects title of table, and harmonizes values with 

Table C-1.

NN 98.408 -

Table NN-2

Table NN–2 to Subpart HH of Part 98—Lookup 

Default Values for Calculation Methodology 2 of 

This Subpart

See Appendix A for changes to Table NN-2 Corrects title of table, and harmonizes values with 

Table C-1.

PP 98.423(a)(3)(i

) 

(3) To aggregate data, use either Equation PP–3a or 

PP–3b in this paragraph, as appropriate.

(i) For facilities with production process units that 

capture 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.

(3) To aggregate data, use either Equation PP–3a or 

PP–3b in this paragraph, as appropriate.

(i) For facilities with production 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.

See preamble text for explanation

PP 98.426(b)(4)(

i) and (ii)

(4) Report density as follows:

(i) Quarterly density of CO2 in metric tons per 

standard cubic meter if you report the concentration 

of the CO2 stream in paragraph (b)(3) of this section 

in weight percent.

(4) Report density as follows:

(i) Quarterly density of the CO2 stream in metric tons 

per standard cubic meter if you report the 

concentration of the CO2 stream in paragraph (b)(3) 

of this section in weight percent.

Clarifies reporting requirement
80

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

(ii) Quarterly density of the CO2 stream in metric 

tons per standard cubic meter if you report the 

concentration of the CO2 stream in paragraph (b)(3) 

of this section in volume percent.

(ii) Quarterly density of CO2 in metric tons per 

standard cubic meter if you report the concentration 

of the CO2 stream in paragraph (b)(3) of this section 

in volume percent.

PP 98.426(f)(10) (10) Enhanced oil and natural gas recovery (10) Injection of CO2 for enhanced oil and natural 

gas recovery that is covered by subpart UU of this 

part.

See preamble text for explanation

PP 98.426(f)(11) (11) Long-term storage (sequestration) (11) Geologic sequestration of carbon dioxide that is 

covered by subpart RR of this part.

See preamble text for explanation

QQ 98.433(a) St = Mass of fluorinated GHG per unit of equipment 

type t or foam type t (charge per piece of equipment 

or cubic foot of foam, kg).

St = Mass of fluorinated GHG per unit of equipment 

type t or foam type t (charge per piece of equipment, 

kg) or density of fluorinated GHG in foam (charge 

per cubic foot of foam, kg per cubic foot).

See preamble text for explanation

QQ 98.433(b) St = Mass in CO2e of the fluorinated GHGs per unit 

of equipment type t or foam type t (charge per piece 

of equipment or cubic foot of foam, kg).

St = Mass in CO2e of the fluorinated GHGs per unit 

of equipment type t or foam type t (charge per piece 

of equipment, kg) or density of fluorinated GHG in 

foam (CO2e per cubic foot of foam, kg CO2e per 

cubic foot). 

Clarifies equation term.

QQ 98.434(b) (b) The inputs to the annual submission must be 

reviewed against the import or export transaction 

records to ensure that the information submitted to 

EPA is being accurately transcribed as the correct 

chemical or blend in the correct pre-charged 

equipment or closed-cell foam in the correct 

quantities (metric tons) and units (kg per piece of 

equipment or cubic foot of foam).

(b) The inputs to the annual submission must be 

reviewed against the import or export transaction 

records to ensure that the information submitted to 

EPA is being accurately transcribed as the correct 

chemical or blend in the correct pre-charged 

equipment or closed-cell foam in the correct 

quantities and units.

Clarifies intent of the requirement.

QQ 98.436(a)(3) (3) For closed-cell foams that are imported inside of 

appliances, the identity of the fluorinated GHG 

contained in the foam in each appliance, the mass of 

the fluorinated GHG contained in the foam in each 

appliance, and the number of appliances imported 

with each unique combination of mass and identity 

of fluorinated GHG within the closed-cell foams.

(3) For closed-cell foams that are imported inside of 

equipment, the identity of the fluorinated GHG 

contained in the foam in each appliance, the mass of 

the fluorinated GHG contained in the foam in each 

piece of equipment, and the number of pieces of 

equipment imported with each unique combination 

of mass and identity of fluorinated GHG within the 

closed-cell foams.

See preamble text for explanation

QQ 98.436(a)(4) (4) For closed cell-foams that are not imported inside 

of appliances, the identity of the fluorinated GHG in 

the foam, the density of the fluorinated GHG in the 

foam (kg fluorinated GHG/cubic foot), and the 

volume of foam imported (cubic feet) for each type 

(4) For closed cell-foams that are not imported inside 

of equipment, the identity of the fluorinated GHG in 

the foam, the density of the fluorinated GHG in the 

foam (kg fluorinated GHG/cubic foot), and the 

volume of foam imported (cubic feet) for each type 

See preamble text for explanation
81

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

of closed-cell foam with a unique combination of 

fluorinated GHG density and identity.

of closed-cell foam with a unique combination of 

fluorinated GHG density and identity.

QQ 98.436(a)(5) (5) Dates on which the pre-charged equipment or 

closed-cell foams were imported.

(5) [Reserved.] See preamble text for explanation

QQ 98.436(a)(6)(i

i)

(ii) For closed-cell foams that are imported inside of 

appliances, the mass of the fluorinated GHGs in 

CO2e contained in the foam in each appliance and 

the number of appliances imported for each type of 

appliance.

(ii) For closed-cell foams that are imported inside of 

equipment, the mass of the fluorinated GHGs in 

CO2e contained in the foam in each piece of 

equipment and the number of pieces of equipment 

imported for each equipment type.

See preamble text for explanation

QQ 98.436(a)(6)(i

ii)

(iii) For closed-cell foams that are not imported 

inside of appliances, the mass in CO2e of the 

fluorinated GHGs in the foam (kg CO2e/cubic foot) 

and the volume of foam imported (cubic feet) for 

each type of closed-cell foam.

(iii) For closed-cell foams that are not imported 

inside of equipment, the density in CO2e of the 

fluorinated GHGs in the foam (kg CO2e/cubic foot) 

and the volume of foam imported (cubic feet) for 

each type of closed-cell foam.

See preamble text for explanation

QQ 98.436(a)(6)(i

v)

(iv) Dates on which the closed-cell foams were 

imported.

(iv) [Reserved.] See preamble text for explanation

QQ 98.436(b)(3) (3) For closed-cell foams that are exported inside of 

appliances, the identity of the fluorinated GHG 

contained in the foam in each appliance, the mass of 

the fluorinated GHG contained in the foam in each 

appliance, and the number of appliances exported 

with each unique combination of mass and identity 

of fluorinated GHG within the closed-cell foams.

(3) For closed-cell foams that are exported inside of 

equipment, the identity of the fluorinated GHG 

contained in the foam in each piece of equipment, 

the mass of the fluorinated GHG contained in the 

foam in each piece of equipment, and the number 

pieces of equipment exported with each unique 

combination of mass and identity of fluorinated 

GHG within the closed-cell foams.

See preamble text for explanation

QQ 98.436(b)(4) (4) For closed-cell foams that are not exported inside 

of appliances, the identity of the fluorinated GHG in 

the foam, the density of the fluorinated GHG in the 

foam (kg fluorinated GHG/cubic foot), and the 

volume of foam exported (cubic feet) for each type 

of closed-cell foam with a unique combination of 

fluorinated GHG density and identity.

(4) For closed-cell foams that are not exported inside 

of equipment, the identity of the fluorinated GHG in 

the foam, the density of the fluorinated GHG in the 

foam (kg fluorinated GHG/cubic foot), and the 

volume of foam exported (cubic feet) for each type 

of closed-cell foam with a unique combination of 

fluorinated GHG density and identity.

See preamble text for explanation

QQ 98.436(b)(5) (5) Dates on which the pre-charged equipment or 

closed-cell foams were exported.

(5) [Reserved.] See preamble text for explanation

QQ 98.436(b)(6)(

ii)

(ii) For closed-cell foams that are exported inside of 

appliances, the mass of the fluorinated GHGs in 

CO2e contained in the foam in each appliance and 

the number of appliances imported for each type of 

(ii) For closed-cell foams that are exported inside of 

equipment, the mass of the fluorinated GHGs in 

CO2e contained in the foam in each piece of 

equipment and the number of pieces of equipment 

See preamble text for explanation
82

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

appliance. imported for each equipment type.

QQ 98.436(b)(6)(

iii)

(iii) For closed-cell foams that are not exported 

inside of appliances, the mass in CO2e of the 

fluorinated GHGs in the foam (kg CO2 e/cubic foot) 

and the volume of foam imported (cubic feet) for 

each type of closed-cell foam.

(iii) For closed-cell foams that are not exported 

inside of equipment, the density in CO2e of the 

fluorinated GHGs in the foam (kg CO2 e/cubic foot) 

and the volume of foam imported (cubic feet) for 

each type of closed-cell foam.

See preamble text for explanation

QQ 98.436(b)(6)i

v)

(6)(iv) Dates on which the closed-cell foams were 

exported.

(6)(iv) [Reserved.] See preamble text for explanation

QQ 98.438 Closed-cell foam means any foam product, excluding 

packaging foam that is constructed with a closed-cell 

structure and a blowing agent containing a 

fluorinated GHG. Closed-cell foams include but are 

not limited to polyurethane (PU) appliance foam, PU 

continuous and discontinuous panel foam, PU one 

component foam, PU spray foam, extruded 

polystyrene (XPS) boardstock foam, and XPS sheet 

foam. Packaging foam means foam used exclusively 

during shipment or storage to temporarily enclose 

items.

Closed-cell foam means any foam product, excluding 

packaging foam that is constructed with a closed-cell 

structure and a blowing agent containing a 

fluorinated GHG. Closed-cell foams include but are 

not limited to polyurethane (PU) foam contained in 

equipment, PU continuous and discontinuous panel 

foam, PU one component foam, PU spray foam, 

extruded polystyrene (XPS) boardstock foam, and 

XPS sheet foam. Packaging foam means foam used 

exclusively during shipment or storage to 

temporarily enclose items.

See preamble text for explanation

QQ 98.438 Pre-charged electrical equipment component means 

any portion of electrical equipment that is charged 

with SF6 or PFCs prior to sale or distribution or offer 

for sale or distribution in interstate commerce.

Pre-charged electrical equipment component means 

any portion of electrical equipment that is charged 

with a fluorinated greenhouse gas prior to sale or 

distribution or offer for sale or distribution in 

interstate commerce.

See preamble text for explanation

RR 98.443 (b)(2) Sr,p= Quarterly mass of contents in containers r that 

is redelivered to another facility without being 

injected into your well in quarter p (metric tons)

Sr,p= Quarterly volume of contents in containers r 

that is redelivered to another facility without being 

injected into your well in quarter p (standard cubic 

meters)

Corrects equation term for consistency of units.

RR 98.443(d)(3) (3) To aggregate production data, you must sum the 

mass of all of the CO2 separated at each gas-liquid 

separator in accordance with the procedure specified 

in Equation RR–9 of this section. You must assume 

that the total CO2 measured at the separator(s) 

represents a percentage of the total CO2 produced. In 

order to account for the percentage of CO2 produced 

that is estimated to remain with the produced oil or 

other fluid, you must multiply the quarterly mass of 

CO2 measured at the separator(s) by a percentage 

estimated using a methodology in your approved 

(3) To aggregate production data, you must sum the 

mass of all of the CO2 separated at each gas-liquid 

separator in accordance with the procedure specified 

in Equation RR–9 of this section. You must assume 

that the total CO2 measured at the separator(s) 

represents a percentage of the total CO2 produced. In 

order to account for the percentage of CO2 produced 

that is estimated to remain with the produced oil or 

other fluid, you must multiply the quarterly mass of 

CO2 measured at the separator(s) by a percentage 

estimated using a methodology in your approved 

Corrects reference.
83

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

MRV plan. If fluids containing CO2 from injection 

wells covered under this source category are 

produced and not processed through a gas-liquid 

separator, the concentration of CO2 in the produced 

fluids must be measured at a flow meter located prior 

to reinjection or reuse using methods in 

§98.444(f)(1). The considerations you intend to use 

to calculate CO2 from produced fluids for the mass 

balance equation must be described in your approved 

MRV plan in accordance with §98.448(d)(5).

MRV plan. If fluids containing CO2 from injection 

wells covered under this source category are 

produced and not processed through a gas-liquid 

separator, the concentration of CO2 in the produced 

fluids must be measured at a flow meter located prior 

to reinjection or reuse using methods in 

§98.444(f)(1). The considerations you intend to use 

to calculate CO2 from produced fluids for the mass 

balance equation must be described in your approved 

MRV plan in accordance with §98.448(a)(5).

RR 98.443(f)(2) CO2FI = Total annual CO2 mass emitted (metric tons) 

from equipment leaks and vented emissions of CO2

from equipment located on the surface between the 

flow meter used to measure injection quantity and 

the injection wellhead. 

CO2FI = Total annual CO2 mass emitted (metric tons) 

from equipment leaks and vented emissions of CO2

from equipment located on the surface between the 

flow meter used to measure injection quantity and 

the injection wellhead, for which a calculation 

procedure is provided in subpart W of this part.

Harmonizing change to conform the variable 

definitions in RR-11 and RR-12

RR 98.446(b)(5) (5) The standard or method used to calculate each 

value in paragraphs (b)(1) and (b)(2) of this section.

(5) The standard or method used to calculate each 

value in paragraphs (b)(1), (b)(2), and (b)(3) of this 

section.

See preamble text for explanation

SS 98.453(d) (d) Estimate the mass of SF6 or PFCs disbursed to 

customers in new equipment or cylinders over the 

period p by monitoring the mass flow of the SF6 or 

PFCs 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.

(d) Estimate the mass of SF6 or PFCs disbursed to 

customers in new equipment or cylinders over the 

period p by monitoring the mass flow of the SF6 or 

PFCs 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.

See preamble text for explanation

SS 98.453(h) (h) The mass of SF6 or the PFC disbursed to 

customers in new equipment over the period p must 

be determined either by using the nameplate capacity 

of the equipment or, in cases where equipment is 

shipped with a partial charge, by calculating the 

partial shipping charge. Calculate the partial shipping 

charge by multiplying the nameplate capacity of the 

equipment by the ratio of the densities of the partial 

charge to the full charge.

To determine the equipment's actual nameplate 

capacity, you must measure the nameplate capacities 

of a representative sample of each make and model 

(h) If the mass of SF6 or the PFC 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.

(1) Determine the equipment's actual nameplate 

capacity, by measuring the nameplate capacities of a 

representative sample of each make and model and 

calculating the mean value for each make and model 

as specified at §98.454(f); 

See preamble text for explanation
84

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

and take the average for each make and model as 

specified at §98.454(f).

(2) If equipment is shipped with a partial charge, 

calculate the partial shipping charge by multiplying 

the nameplate capacity of the equipment by the ratio 

of the densities of the partial charge to the full 

charge.

SS 98.453(i) MF = The total annual mass of the SF6 or PFCs, in 

pounds, used to fill equipment.

MF = The total annual mass of the SF6 or PFCs, in 

pounds, used to fill equipment during equipment 

installation at electric transmission or distribution 

facilities.

Clarifies a calculation term. 

SS 98.456(m) (m) The values for each hose and valve combination 

and the associated valve fitting sizes and hose 

diameters.

(m) The values for EFCi of Equation SS-5 of this 

subpart for each hose and valve combination and the 

associated valve fitting sizes and hose diameters.

Clarifies a reporting requirement.

SS 98.456(o) & 

(p)

(o) The mean value for each make, model, and group 

of conditions if the mass of SF6 or the PFC disbursed 

to customers in new equipment over the period p is 

determined by assuming that it is equal to the 

equipment's nameplate capacity or, in cases where 

equipment is shipped with a partial charge, equal to 

its partial shipping charge.

(p) The number of samples and the upper and lower 

bounds on the 95 percent confidence interval for 

each make, model, and group of conditions if the 

mass of SF6 or the PFC disbursed to customers in 

new equipment over the period p is determined by 

assuming that it is equal to the equipment's 

nameplate capacity or, in cases where equipment is 

shipped with a partial charge, equal to its partial 

shipping charge.

(o) If the mass of SF6 or the PFC disbursed to 

customers in new equipment over the period p is 

determined according to the methods required in 

§98.453(h) of this subpart, report the mean value of 

nameplate capacity in pounds for each make, model, 

and group of conditions. 

(p) If the mass of SF6 or the PFC disbursed to 

customers in new equipment over the period p is 

determined according to the methods required in 

§98.453(h) of this subpart, 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.

Clarifies a reporting requirement.

TT 98.460(c)(2)(

xiii)

(xiii) Other waste material that has a DOC value of 

0.3 weight percent (on a wet basis) or less. DOC 

value must be determined using a 60-day anaerobic 

biodegradation test procedure identified in § 

98.464(b)(4)(i)(A) .

(xiii) Other waste material that has a DOC value of 

0.3 weight percent (on a wet basis) or less. DOC 

value must be determined using a 60-day anaerobic 

biodegradation test procedure identified in § 

98.464(b)(4)(i) .

Corrects cross-reference to 98.464(b)(4)(i) to 

indicate that all of the requirements in subparagraph 

(A) through (E) are applicable.

TT 98.463(a)(1) DOCF= Fraction of DOC dissimilated (fraction); use 

the default value of 0.5.

DOCF= Fraction of DOC dissimilated (fraction); use 

the default value of 0.5. If measured values of DOC 

are available using the 60-day anaerobic 

biodegradation test procedure identified in 

See preamble text for explanation
85

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

98.464(b)(4)(i), use a default value of 1.0 .

TT 98.463(a)(1)

Eq. TT-1

Fx = Fraction by volume of CH4 in landfill gas 

(fraction, dry basis, corrected to 0% oxygen). If you 

have a gas collection system, use the annual average 

CH4 concentration from measurement data for the 

current reporting year; otherwise, use the default 

value of 0.5.

F = Fraction by volume of CH4 in landfill gas 

(fraction, dry basis, corrected to 0% oxygen). If you 

have a gas collection system, use the annual average 

CH4 concentration from measurement data for the 

current reporting year; otherwise, use the default 

value of 0.5.

Corrects an equation term. This term corresponds to 

a factor for the current reporting year, and should not 

have a subscript indicating that it is a variable that 

changes with each disposal year. 

TT 98.463(a)(2)(i

i)(C )

Eq. TT-4b

Corrects a typographical error in Equation TT-4b. 

The summation should start with "n=1" rather than 

"n-1"

TT 98.463(b)(1) 

Eq. TT-6

OX = Oxidation fraction. Use the default value of 0.1 

(10 percent).

OX = Oxidation fraction from Table HH-4 of subpart 

HH of this part. 

See preamble text for explanation

TT 98.464(b) (b) For each waste stream placed in the landfill 

during the reporting year for which you choose to 

determine volatile solids concentration for the 

purposes of § 98.460(c)(2)(xii) or choose to 

determine a landfill-specific DOCX for use in 

Equation TT-1 of this subpart or for the purposes of 

§ 98.460(c)(2)(xiii) of this subpart, you must collect 

and test a representative sample of that waste stream 

using the methods specified in paragraphs (b)(1) 

through (b)(4) of this section.

(b) For each waste stream placed in the landfill 

during the reporting year for which you choose to 

determine volatile solids concentration and/or a 

waste stream-specific DOCX, you must collect and 

test a representative sample of that waste stream 

using the methods specified in paragraphs (b)(1) 

through (b)(4) of this section, as applicable.

See preamble text for explanation

TT 98.464(b)(4)(

i)(E)

Eq. TT-7

Where:

DOCX= Degradable organic content of the waste stream in Year 

X (weight fraction, wet basis)

DOCF= Fraction of DOC dissimilated (fraction); use the default 

value of 0.5.

MCDsample,x= Mass of carbon degraded in the waste stream 

sample in Year X as determined in paragraph (b)(4)(i)(C) of this 

Where:

DOCX= Degradable organic content of the waste 

stream in Year X (weight fraction, wet basis)

MCDsample,x= Mass of carbon degraded in the waste 

stream sample in Year X as determined in paragraph 

(b)(4)(i)(C) of this section [milligrams (mg)].

Msample,x= Mass of waste stream sample used in the 

anaerobic degradation test in Year X (mg, wet basis).

See preamble text for explanation

NYrData

n

Wmeas n

1

,

NYrData

n

Wmeas n

1

,

control

control

sample x

sample x

F

X MC

MCD

M

MCD

DOC

DOC

,

1 ,

sample x

sample x

X M

MCD

Doc

,

,
86

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

section [milligrams (mg)].

Msample,x= Mass of waste stream sample used in the anaerobic 

degradation test in Year X (mg, wet basis).

MCDcontrol= Mass of carbon degraded in the control sample as 

determined in paragraph (b)(4)(i)(B) of this section (mg).

MCcontrol= Mass of carbon added to the control sample via the 

substrate material in the anaerobic degradation (mg).

TT 98.464(c) (c) For each waste stream for which you choose to 

determine volatile solids concentration for the 

purposes of paragraph § 98.460(c)(2)(xii), and that 

was historically managed in the landfill but was not 

received during the first reporting year, you must 

determine volatile solids concentration of the waste 

stream as initially placed in the landfill using the 

methods specified in paragraph (c)(1) or (c)(2) of 

this section, as applicable.

(c) For each waste stream that was historically 

managed in the landfill but was not received during 

the first reporting year for which you choose to 

determine volatile solids concentration and/or a 

waste stream-specific DOCX, you must determine 

volatile solids concentration or DOCX of the waste 

stream as initially placed in the landfill using the 

methods specified in paragraph (c)(1) or (c)(2) of 

this section, as applicable.

See preamble text for explanation

TT 98.464(c)(1) (1) If you can identify a similar waste stream to the 

waste stream that was historically managed in the 

landfill, you must determine the volatile solids 

concentration of the similar waste stream using the 

procedures in paragraphs (b)(1) through (b)(3) of this 

section.

(1) If you can identify a similar waste stream to the 

waste stream that was historically managed in the 

landfill, you must determine the volatile solids 

concentration or DOCX of the similar waste stream 

using the applicable procedures in paragraphs (b)(1) 

through (b)(4) of this section.

See preamble text for explanation

TT 98.464(c)(2) (2) If you cannot identify a similar waste stream to 

the waste stream that was historically managed in the 

landfill, you may determine the volatile solids 

concentration of the historically managed waste 

stream using process knowledge. You must 

document the basis for volatile solids concentration 

as determined through process knowledge.

(2) If you cannot identify a similar waste stream to 

the waste stream that was historically managed in the 

landfill, you may determine the volatile solids 

concentration or DOCX of the historically managed 

waste stream using process knowledge. You must 

document the basis for the volatile solids 

concentration or DOCX value as determined through 

process knowledge.

See preamble text for explanation

TT 98.466(b)(1) (1) The number of waste steams (including ―Other 

Industrial Solid Waste (not otherwise listed)‖) for 

which Equation TT-1 of this subpart is used to 

calculate modeled CH4 generation.

(1) The number of waste steams (including ―Other 

Industrial Solid Waste (not otherwise listed)‖ and 

―Inerts ‖) for which Equation TT–1 of this subpart is 

used to calculate modeled CH4 generation.

See preamble text for explanation

TT 98.466(b)(5) (None) (5) For each waste stream, the decay rate (k) value 

used in the calculations. 

See preamble text for explanation

TT 98.466(c ) (c) For each waste stream identified in paragraph (b) 

of this section, report the following information:

(1) The decay rate (k) value used in the calculations.

(c) Report the following historical waste 

information:

(1) [Reserved]

See preamble text for explanation
87

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

(2) The method(s) for estimating historical waste

disposal quantities and the range of years for which 

each method applies. 

(3) If Equation TT–2 of this subpart is used, provide:

(i) The total number of years (N) for which disposal 

and production data are both available.

(ii) The year, the waste disposal quantity and 

production quantity for each year used in Equation 

TT–2 of this subpart to calculate the average waste 

disposal factor (WDF).

(iii) The average waste disposal factor (WDF) 

calculated for the waste stream.

(2) For each waste stream identified in paragraph (b) 

of this section, the method(s) for estimating 

historical waste disposal quantities and the range of 

years for which each method applies.

(3) For each waste stream identified in paragraph (b) 

of this section for which Equation TT-2 of this 

subpart is used, provide:

(i) The total number of years (N) for which disposal 

and production data are both available.

(ii) The year, the waste disposal quantity and 

production quantity for each year used in Equation 

TT–2 of this subpart to calculate the average waste 

disposal factor (WDF).

(iii) The average waste disposal factor (WDF) 

calculated for the waste stream.

TT 98.466(c)(4) (4) If Equation TT-4 of this subpart is used, provide:

(i) The value of landfill capacity (LFC).

(ii) YrData.

(iii) YrOpen.

(4) If Equation TT–4a of this subpart is used, 

provide:

(i) The value of landfill capacity (LFC).

(ii) YrData.

(iii) YrOpen.

See preamble text for explanation

TT 98.466(c)(5) (None) (5) If Equation TT-4b of this subpart is used, 

provide: 

(i) WIP (i.e., the quantity of waste in-place at the 

start of the reporting year from design drawings or 

engineering estimates (metric tons) or, for closed 

landfills for which waste in-place quantities are not 

available, the landfill's design capacity); 

(ii) The cumulative quantity of waste placed in the 

landfill for the years for which disposal quantities are 

available from company record or from Equation 

TT-3 of this part; 

(iii) YrLast; 

(iv) YrOpen; and 

(v) NYrData.

See preamble text for explanation

TT 98.466(d)(3) (3) The degradable organic carbon (DOCX ) value 

(mass fraction) for the specified year and an 

indication as to whether this was the default value 

from Table TT-1 to this subpart, a measured value 

(3) For each waste stream, the degradable organic 

carbon (DOCX) value (mass fraction) for the 

specified year and an indication as to whether this 

was the default value from Table TT–1 to this 

See preamble text for explanation
88

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

using a 60-day anaerobic biodegradation test as 

specified in §98.464(b)(4)(i), or a value based on 

total and volatile solids measurements as specified in 

§98.464(b)(4)(ii). If DOCX was determined by a 60-

day anaerobic biodegradation test, specify the test 

method used.

subpart, a measured value using a 60-day anaerobic 

biodegradation test as specified in §98.464(b)(4)(i), 

or a value based on total and volatile solids

measurements as specified in §98.464(b)(4)(ii). If 

DOCX was determined by a 60-day anaerobic 

biodegradation test, specify the test method used.

TT 98.466(h) (h) For landfills with gas collection systems, in 

addition to the reporting requirements in paragraphs 

(a) through (f) of this section, you must report 

according to §98.346(i).

(h) For landfills with gas collection systems, in 

addition to the reporting requirements in paragraphs 

(a) through (f) of this section, provide: 

(1) The annual methane generation, adjusted for 

oxidation, calculated using Equation TT-6 of this 

subpart, reported in metric tons CH4;

(2) The oxidation factor used in Equation TT-6 of 

this subpart; and

(3) All information required under 40 CFR 

98.346(i)(1) through (i)(7) and 40 CFR 98.346(i)(9) 

through (i)(12). 

See preamble text for explanation

TT 98.467 In addition to the information required by §98.3(g), 

you must retain the calibration records for all 

monitoring equipment, including the method or 

manufacturer's specification used for calibration, and 

all measurement data used for the purposes of 

paragraph § 98.460(c)(2)(xii) or used to determine 

landfill-specific DOCX values.

In addition to the information required by §98.3(g), 

you must retain the calibration records for all 

monitoring equipment, including the method or 

manufacturer's specification used for calibration, and 

all measurement data used for the purposes of 

paragraphs §98.460(c)(2)(xii) or (c)(2)(xiii) or used 

to determine waste stream-specific DOCX values for 

use in Equation TT-1 of this subpart.

See preamble text for explanation

TT Table TT-1 Table TT-1 See Appendix A for changes to Table TT-1 See preamble text for explanation

UU 98.473(a)(2) D= Density of CO2 at standard conditions (metric 

tons per standard cubic meter): 0.0018704 

D= Density of CO2 at standard conditions (metric 

tons per standard cubic meter): 0.0018682

Harmonizing change to conform with the density 

values used in 98.473(b)(2).

UU 98.473(b)(2) Sr,p= Quarterly mass of contents in containers r that 

is redelivered to another facility without being 

injected into your well in quarter p (standard cubic 

meters)

Sr,p= Quarterly volume of contents in containers r 

that is redelivered to another facility without being 

injected into your well in quarter p (standard cubic 

meters)

Corrects equation term for consistency of units.

UU 98.476(b)(5) (5) The standard or method used to calculate each 

value in paragraphs (b)(1) and (b)(2) of this section.

(5) The standard or method used to calculate each 

value in paragraphs (b)(1), (b)(2), and (b)(3) of this 

section.

See preamble text for explanation

UU 98.476(e) (None) (e) Report the following:

(1) Whether the facility received a Research and 

Development project exemption from reporting 

See preamble text for explanation
89

Subpart Requirement Current Rule Text Proposed Rule Text Rationale for Change

under 40 CFR Part 98 subpart RR for this reporting 

year. If you received an exemption, report the start 

and end dates of the exemption approved by EPA;

(2) Whether the facility includes a well or group of 

wells where a CO2 stream was injected into 

subsurface geologic formations to enhance the 

recovery of oil during this reporting year;

(3) Whether the facility includes a well or group of 

wells where a CO2 stream was injected into 

subsurface geologic formations to enhance the 

recovery of natural gas during this reporting year;

(4) Whether the facility includes a well or group of 

wells where a CO2 stream was injected into 

subsurface geologic formations for acid gas disposal 

during this reporting year; 

(5) Whether the facility includes a well or group of 

wells where a CO2 stream was injected for a purpose 

other than those listed in (e)(1)through (4) of this 

section. If you injected CO2 for another purpose, 

report the purpose of the injection.
Attachment A

1. Proposed Amendments to Table A–1 to Subpart A of Part 98—Global Warming 

Potentials

[100-Year Time Horizon]

Table A–1 to Subpart A of Part 98—Global Warming Potentials

[100-Year Time Horizon]

Name CAS No. Chemical formula

Global warming 

potential

(100 yr.)

Carbon dioxide 124–38–9CO2 1

Methane 74–82–8CH4 2125a

Nitrous oxide 10024–97–2N2O 310298a

HFC–23 75–46–7CHF3 11,70014,800a

HFC–32 75–10–5CH2F2 650675a

HFC–41 593–53–3CH3F 15092a

HFC–125 354–33–6C2HF5 2,8003,500a

HFC–134 359–35–3C2H2F4 1,000100a

HFC–134a 811–97–2CH2FCF3 1,300430a

HFC–143 430–66–0C2H3F3 300353a

HFC–143a 420–46–2C2H3F3 3,8004,470a

HFC–152 624–72–6CH2FCH2F 53

HFC–152a 75–37–6CH3CHF2 140124a

HFC–161 353–36–6CH3CH2F 12

HFC–227ea 431–89–0C3HF7 2,9003,220a

HFC–236cb 677–56–5CH2FCF2CF3 1,340

HFC–236ea 431–63–0CHF2CHFCF3 1,370

HFC–236fa 690–39–1C3H2F6 9,8106,300a

HFC–245ca 679–86–7C3H3F5 693560a

HFC–245fa 460–73–1CHF2CH2CF3 1,030

HFC–365mfc 406–58–6CH3CF2CH2CF3 794
Name CAS No. Chemical formula

Global warming 

potential

(100 yr.)

HFC–43–10mee 138495–42–8CF3CFHCFHCF2CF3 1,300640a

Sulfur hexafluoride 2551–62–4SF6 23,90022,800a

Trifluoromethyl sulphur 

pentafluoride

373–80–8SF5CF3 17,700

Nitrogen trifluoride 7783–54–2NF3 17,200

PFC–14 (Perfluoromethane) 75–73–0CF4 6,5007,390a

PFC–116 (Perfluoroethane) 76–16–4C2F6 9,20012,200a

PFC–218 (Perfluoropropane) 76–19–7C3F8 7,0008,830a

Perfluorocyclopropane 931–91–9C-C3F6 17,340

PFC–3–1–10 (Perfluorobutane) 355–25–9C4F10 7,0008,860a

Perfluorocyclobutane 115–25–3C-C4F8 8,70010,300a

PFC–4–1–12 (Perfluoropentane) 678–26–2C5F12 7,5009,160a

PFC–5–1–14

(Perfluorohexane)

355–42–0C6F14 7,4009,300a

PFC–9–1–18 306–94–5C10F18 7,500

HCFE–235da2 (Isoflurane) 26675–46–7CHF2OCHClCF3 350

HFE–43–10pccc (H–Galden 1040x) E1730133CHF2OCF2OC2F4OC

HF2

1,870

HFE–125 3822–68–2CHF2OCF3 14,900

HFE–134 1691–17–4CHF2OCHF2 6,320

HFE–143a 421–14–7CH3OCF3 756

HFE–227ea 2356–62–9CF3CHFOCF3 1,540

HFE–236ca12 (HG–10) 78522–47–1CHF2OCF2OCHF2 2,800

HFE–236ea2 (Desflurane) 57041–67–5CHF2OCHFCF3 989

HFE–236fa 20193–67–3CF3CH2OCF3 487

HFE–245cb2 22410–44–2CH3OCF2CF3 708

HFE–245fa1 84011–15–4CHF2CH2OCF3 286

HFE–245fa2 1885–48–9CHF2OCH2CF3 659

HFE–254cb2 425–88–7CH3OCF2CHF2 359
Name CAS No. Chemical formula

Global warming 

potential

(100 yr.)

HFE–263fb2 460–43–5CF3CH2OCH3 11

HFE-329mcc2 67490-36-2 CF3CF2OCF2CHF2 919

HFE–338mcf2 156053–88–2CF3CF2OCH2CF3 552

HFE–338pcc13 (HG–01) 188690–78–0CHF2OCF2CF2OCHF2 1,500

HFE–347mcc3 28523–86–6CH3OCF2CF2CF3 575

HFE–347mcf2 E1730135CF3CF2OCH2CHF2 374

HFE–347pcf2 406–78–0CHF2CF2OCH2CF3 580

HFE–356mec3 382–34–3CH3OCF2CHFCF3 101

HFE–356pcc3 160620–20–2CH3OCF2CF2CHF2 110

HFE–356pcf2 E1730137CHF2CH2OCF2CHF2 265

HFE–356pcf3 35042–99–0CHF2OCH2CF2CHF2 502

HFE–365mcf3 378–16–5CF3CF2CH2OCH3 11

HFE–374pc2 512–51–6CH3CH2OCF2CHF2 557

HFE–449s1l (HFE–7100)

Chemical blend

163702–07–6

163702–08–7

C4F9OCH3

(CF3)2CFCF2OCH3

297

HFE–569sf2 (HFE–7200)

Chemical blend

163702–05–4

163702–06–5

C4F9OC2H5

(CF3)2CFCF2OC2H5

59

Sevoflurane 28523–86–6CH2FOCH(CF3)2 345

HFE–356mm1 13171–18–1(CF3)2CHOCH3 27

HFE–338mmz1 26103–08–2CHF2OCH(CF3)2 380

(Octafluorotetramethylene)hydroxymethyl groupNAX-(CF2)4CH(OH)-X 73

HFE–347mmy1 22052–84–2CH3OCF(CF3)2 343

Bis(trifluoromethyl)-methanol 920–66–1(CF3)2CHOH 195

2,2,3,3,3-pentafluoropropanol 422–05–9CF3CF2CH2OH 42

PFPMIE NACF3OCF(CF3)CF2OCF

2OCF3

10,300

HFC-1234ze b29118-24-9C3H2F4 6

hexafluoropropylene (HFP) b116-15-4C3F6 0.25
Name CAS No. Chemical formula

Global warming 

potential

(100 yr.)

perfluoromethyl vinyl ether (PMVE)b1187-93-5CF(CF3)OCF3 3

tetrafluoroethylene (TFE)b116-14-3C2F4 0.02

trifluoro propene (TFP)b677-21-4C3H3F3 3

vinyl fluoride (VF)b75-02-5C2H3F 0.7

vinylidiene fluoride (VF2)b75-38-7C2H2F2 0.9

carbonyl fluoride b353-50-4COF2 2

perfluoropropyl vinyl etherb1623-05-8C5F10O 3

perfluoroethyl vinyl etherb10493-43-3C4F8O 3

HFC-1234yf b754-12-1C3H2F4 4

perfluorethyl iodide (2-I)b354-64-3C2F5I 3

perfluorbutyl iodide (PFBI, 42-I) b423-39-2C4F9I 3

perfluorhexyl iodide (6-I)b355-43-1

CF3CF2CF2CF2CF2CF2I

C6F13I

2

perfluoroctyl iodide (8-I)b507-63-1C8F17I 2

1,1,1,2,2-pentafluoro-4-iodo butane 

(22-I) b40723-80-6C4H4F5I

2

1,1,1,2,2,3,3,4,4-nonafluoro-6-iodo 

hexane (42-I) b2043-55-2C6H4F9I

2

perfluorobutyl ethene (42-U)b19430-93-4C6H3F9 2

perfluorohexyl ethene (62-U)b25291-17-2C8H3F13 1

perfluorooctyl ethene (82-U)b21652-58-4C10H3F17 1

1H,1H, 2H,2H-perfluorohexan-1-ol (42-

AL)b2043-47-2C6H5F9O

5

FK-5-1-12 Perfluoroketone; FK-5-1-

12myy2; n-Perfluorooctane; 

Octanedecafluorooctaneb756-13-8CF3CF2C(O)CF (CF3)2

1.8

C7 Fluoroketone, Novec 774/ FK-6-1-

12

813-44-5 and 

813-45-6C7F14O Chemical Blend

1

trans-1-chloro-3,3,3-trifluoroprop-1-ene

b

2730-43-0C3H2ClF3

7

Hexadecofluoroheptane b

(PFC-6-1-12) 335-57-9C7F16

7930
Name CAS No. Chemical formula

Global warming 

potential

(100 yr.)

octadecafluorooctane b

(PFC-7-1-18) 307-34-6C8F18

8340

a The GWP for this compound is different than the GWP in the version of Table A-1 to subpart A 

of part 98 published on October 30, 2009.

b The GWP for this compound was not provided in the version of Table A-1 to subpart A of part 

98 published on October 30, 2009.

NA – Not available

3. Proposed Amendments to Table A-6 to 40 CFR part 98, subpart A:

Table A–6 to Subpart A of Part 98—Data Elements That Are Inputs 

to Emission Equations and for Which the Reporting Deadline Is 

March 31, 2013

Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which 

reporting date is March 31, 2013 

(―All‖ means all data elements in the 

cited paragraph are not required to 

be reported until March 31, 2013)

C 98.36(d)(1)(iv) All.

C 98.36(d)(2)(ii)(G) All.

C 98.36(d)(2)(iii)(G) All.

C 98.36(e)(2)(iv)(G) All.

C 98.36(e)(2)(viii)(A)All.

C 98.36(e)(2)(viii)(B)All.

C 98.36(e)(2)(viii)(C)All.

C 98.36(e)(2)(x)(A) All.

C 98.36(e)(2)(xi) All.

DD 98.306(a)(2) All.

DD 98.306(a)(3) All.

DD 98.306(d) All.

DD 98.306(e) All.

DD 98.306(f) All.
Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which 

reporting date is March 31, 2013 

(―All‖ means all data elements in the 

cited paragraph are not required to 

be reported until March 31, 2013)

DD 98.306(g) All.

DD 98.306(h) All.

DD 98.306(i) All.

DD 98.306(j) All.

DD 98.306(k) All.

DD 98.306(l) All.

FF 98.326(a) All.

FF 98.326(b) All.

FF 98.326(c) All.

FF 98.326(f) Only quarterly volumetric flow rate.

FF 98.326(g) Only quarterly CH4 concentration.

FF 98.326(h) Only weekly volumetric flow used to 

calculate CH4 liberated from 

degasification systems.

FF 98.326(j) All.

FF 98.326(k) All.

FF 98.326(o) All.

FF 98.326(p) Only assumed destruction efficiency 

for the primary destruction device 

and assumed destruction efficiency 

for the backup destruction device.

HH 98.346(a) Only year in which landfill first 

accepted waste, last year the 

landfill accepted waste (if used as 

an input in Equation HH–3), capacity 

of the landfill (if used as an input 

in Equation HH–3), and waste disposal 

quantity for each year of 

landfilling.

HH 98.346(b) Only quantity of waste determined 

using the methods in 

§98.343(a)(3)(i), quantity of waste 
Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which 

reporting date is March 31, 2013 

(―All‖ means all data elements in the 

cited paragraph are not required to 

be reported until March 31, 2013)

determined using the methods in 

§98.343(a)(3)(ii), population served 

by the landfill for each year, and 

the value of landfill capacity (LFC) 

used in the calculation.

HH 98.346(c) All.

HH 98.346(d)(1) Only degradable organic carbon (DOC) 

value, methane correction factor 

(MCF) values, and fraction of DOC 

dissimilated (DOCF) values.

HH 98.346(d)(2) All.

HH 98.346(e) Only fraction of CH4 in landfill gas

and methane correction factor (MCF) 

values.

HH 98.346(f) Only surface area associated with 

each cover type.

HH 98.346(g) All.

HH 98.346(i)(5) Only annual operating hours for the 

primary destruction device, annual 

operating hours for the backup 

destruction device, destruction 

efficiency for the primary 

destruction device, and destruction 

efficiency for the backup destruction 

device.

HH 98.346(i)(6) All.

HH 98.346(i)(7) Only surface area specified in Table 

HH–3, estimated gas collection system 

efficiency, and annual operating 

hours of the gas collection system.

HH 98.346(i)(9) Only CH4 generation value.

II 98.356(b)(1) All.

II 98.356(b)(2) All.

II 98.356(b)(3) All.
Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which 

reporting date is March 31, 2013 

(―All‖ means all data elements in the 

cited paragraph are not required to 

be reported until March 31, 2013)

II 98.356(b)(4) All.

II 98.356(b)(5) All.

II 98.356(d)(1) All.

II 98.356(d)(7) All.

II 98.356(d)(8) Only annual operating hours for the 

primary destruction device, annual 

operating hours for the backup 

destruction device, destruction 

efficiency of the primary destruction 

device, and destruction efficiency of 

the backup destruction device.

SS 98.456(a) All.

SS 98.456(b) All.

SS 98.456(c) All.

SS 98.456(d) All.

SS 98.456(e) All.

SS 98.456(f) All.

SS 98.456(g) All.

SS 98.456(h) All.

SS 98.456(i) All.

SS 98.456(j) All.

SS 98.456(m) All.

SS 98.456(n) All.

SS 98.456(o) All.

SS 98.456(q) All.

SS 98.456(r) All.

SS 98.456(s) All.

SS 98.456(t) Only for any missing data the 

substitute parameters used to 
Subpart

Rule citation

(40 CFR part 98)

Specific data elements for which 

reporting date is March 31, 2013 

(―All‖ means all data elements in the 

cited paragraph are not required to 

be reported until March 31, 2013)

estimate emissions in their absence.

TT 98.466(a)(2) All.

TT 98.466(a)(3) Only last year the landfill accepted 

waste (for closed landfills using 

Equation TT–4).

TT 98.466(a)(4) Only capacity of the landfill in 

metric tons (for closed landfills 

using Equation TT–4).

TT 98.466(c)(1) All.

TT 98.466(c)(4)(i) All.

TT 98.466(c)(4)(ii) All.

TT 98.466(c)(4)(iii) All.

TT 98.466(d)(1) All.

TT 98.466(d)(2) Only degradable organic carbon (DOCX) 

value used in calculations.

TT 98.466(d)(3) Only fraction of CH4 in landfill gas.

TT 98.466(e)(2) Only surface area (in square meters) 

at the start of the reporting year 

for the landfill sections that 

contain waste and that are associated 

with the selected cover type (for 

facilities using a landfill gas 

collection system).

TT 98.466(f) All.
4. Proposed Amendments to Table C-1 to 40 CFR part 98, subpart C:

Table C–1 to Subpart C—Default CO&ihel2CO2; Emission Factors and 

High Heat Values for Various Types of Fuel

Fuel type Default high heat value

Default CO2

emission factor

Coal and coke mmBtu/short ton kg CO2/mmBtu

Anthracite 25.09 103.5469

Waste Anthracite (Culm) See footnote 1 103.69

Bituminous 24.93 93.4028

Waste Bituminous (Gob) See footnote 1 93.28

Subbituminous 17.25 97.0217

Lignite 14.21 96.3697.72

Coal Coke 24.80 102.04113.67

Mixed (Commercial sector) 21.39 95.2694.27

Mixed (Industrial coking) 26.28 93.6590

Mixed (Industrial sector) 22.35 93.9194.67

Mixed (Electric Power sector) 19.73 94.3895.52

Natural gas mmBtu/scf kg CO2/mmBtu

(Weighted U.S. Average) 1.028026 × 10−3 53.026

Petroleum products mmBtu/gallon kg CO2/mmBtu

Distillate Fuel Oil No. 1 0.139 73.25

Distillate Fuel Oil No. 2 0.138 73.96

Distillate Fuel Oil No. 4 0.146 75.04

Residual Fuel Oil No. 5 0.140 72.93

Residual Fuel Oil No. 6 0.150 75.10

Used Oil 0.135138 74.00

Kerosene 0.135 75.20

Liquefied petroleum gases (LPG)20.092 62.9861.71

Propane20.091 61.4662.87

Propylene20.091 65.9567.77

Ethane20.069068 62.6459.60
Fuel type Default high heat value

Default CO2

emission factor

Ethanol 0.084 68.44

Ethylene30.100058 67.4365.96

Isobutane20.097099 64.9164.94

Isobutylene20.103 67.7468.86

Butane20.101103 65.1564.77

Butylene20.103105 67.7368.72

Naphtha (<401 deg F) 0.125 68.02

Natural Gasoline 0.110 66.883

Other Oil (>401 deg F) 0.139 76.22

Pentanes Plus 0.110 70.02

Petrochemical Feedstocks 0.129125 70.9771.02

Petroleum Coke 0.143 102.41

Special Naphtha 0.125 72.34

Unfinished Oils 0.139 74.4954

Heavy Gas Oils 0.148 74.92

Lubricants 0.144 74.27

Motor Gasoline 0.125 70.22

Aviation Gasoline 0.120 69.25

Kerosene-Type Jet Fuel 0.135 72.22

Asphalt and Road Oil 0.158 75.36

Crude Oil 0.138 74.4954

Other fuels-solid mmBtu/short ton kg CO2/mmBtu

Municipal Solid Waste 9.95490.7

Tires 26.8728.00 85.97

Plastics 38.00 75.00

Petroleum Coke 30.00 102.41

Other fuels—gaseous mmBtu/scf kg CO2/mmBtu

Blast Furnace Gas 0.092 × 10−3 274.32
Fuel type Default high heat value

Default CO2

emission factor

Coke Oven Gas 0.599 × 10−3 46.85

Propane Gas 2.516 × 10−3 61.46

Fuel Gas251.388 × 10−3 59.00

Biomass fuels—solid mmBtu/short ton kg CO2/mmBtu

Wood and Wood Residuals(dry basis)615.3817.48 93.80

Agricultural Byproducts 8.25 118.17

Peat 8.00 111.84

Solid Byproducts 25.8310.39 105.51

Biomass fuels—gaseous mmBtu/scf kg CO2/mmBtu

Biogas (Captured methane)Landfill Gas 0.841485 × 10−3 52.07

Other Biomass Gases 0.655 x 10-352.07

Biomass Fuels—Liquid mmBtu/gallon kg CO2/mmBtu

Ethanol 0.084 68.44

Biodiesel 0.128 73.84

Biodiesel (100%) 0.128 73.84

Rendered Animal Fat 0.125 71.06

Vegetable Oil 0.120 81.55

1 Provisions of the rule referencing ―default HHVs from Table C-1‖ do 

not apply to culm and gob. The HHV for culm and gob must be 

determined according to the procedures specified in the Tier 2 

Calculation Methodology.

2 The HHV for components of LPG determined at 60oF and saturation 

pressure with the exception of ethylene.

3Ethylene HHV determined at 41oF (5oC) and saturation pressure.

4Use of this default HHV is allowed only for: (a) Units that combust 

MSW, do not generate steam, and are allowed to use Tier 1; (b) units 

that derive no more than 10 percent of their annual heat input from 

MSW and/or tires; and (c) small batch incinerators that combust no 

more than 1,000 tons of MSW per year.

5Reporters subject to subpart X of this part that are complying with 

§98.243(d) or subpart Y of this part may only use the default HHV and 

the default CO2 emission factor for fuel gas combustion under the 
conditions prescribed in §98.243(d)(2)(i) and (d)(2)(ii) and 

§98.252(a)(1) and (a)(2), respectively. Otherwise, reporters subject 

to subpart X or subpart Y shall use either Tier 3 (Equation C–5) or 

Tier 4.

6Use the following formula to calculate a wet basis HHV for use in 

Equation C-1: HHVw=((100-M)/100)*HHVd where HHVw = wet basis HHV, M = 

moisture content(percent) and HHVd=dry basis HHV from Table C-1.

5. Proposed Amendments to Table C-2 to 40 CFR part 98, subpart C:

Table C–2 to Subpart C—Default CH&ihel4CH4; and N&ihel2;ON2O

Emission Factors for Various Types of Fuel

Fuel type

Default CH&ihel4CH4;

emission factor (kg 

CH&ihel4CH4;/mmBtu)

Default N&ihel2;ON2O

emission factor (kg 

N&ihel2;ON2O/mmBtu)

Coal and Coke (All fuel 

types in Table C–1)1

1.1 × 10−02 1.6 × 10−03

Anthracite for FBCs only21.1 x 10-02 1.6 x 10-01

Waste Anthracite (Culm) 

for FBCs only2

1.1 x 10-02 4.0 x 10-01

Bituminous for FBCs only21.1 x 10-02 1.3 x 10-01

Waste Bituminous (Gob) 

for FBCs only2

1.1 x 10-02 2.9 x 10-01

Subbituminous for FBCs 

only2

1.1 x 10-02 6.5 x 10-02

Lignite for FBCs only21.1 x 10-02 1.1 x 10-01

Natural Gas 1.0 × 10−03 1.0 × 10−04

Petroleum (All fuel types in 

Table C–1)

3.0 × 10−03 6.0 × 10−04

Fuel Gas 3.0 × 10−03 6.0 × 10−04

Municipal Solid Waste 3.2 × 10−02 4.2 × 10−03

Tires 3.2 × 10−02 4.2 × 10−03

Blast Furnace Gas 2.2 × 10−05 1.0 × 10−04

Coke Oven Gas 4.8 × 10−04 1.0 × 10−04

Biomass Fuels—Solid (All 

fuel types in Table C–1), 

except wood and wood 

residuals)

3.2 × 10−02 4.2 × 10−03
Fuel type

Default CH&ihel4CH4;

emission factor (kg 

CH&ihel4CH4;/mmBtu)

Default N&ihel2;ON2O

emission factor (kg 

N&ihel2;ON2O/mmBtu)

Wood and wood residuals 7.2 x 10-33.6 x 10-3

BiogasBiomass FuelsGaseous (All fuel types in 

Table C-1)

3.2 × 10−03 6.3 × 10−04

Biomass Fuels—Liquid 

(All fuel types in Table C–

1)

1.1 × 10−03 1.1 × 10−04

1Use of the default emission factors for the coal and coke category may 

not be used to estimate emissions from combusting anthracite, waste 

anthracite, bituminous, waste bituminous, subbituminous, or lignite 

coal burned in an FBC.

2Use of these default emission factors is required for FBCs burning the 

specified coal type.

Note: Those employing this table are assumed to fall under the IPCC 

definitions of the ―Energy Industry‖ or ―Manufacturing Industries and 

Construction‖. In all fuels except for coal the values for these two 

categories are identical. For coal combustion, those who fall within 

the IPCC ―Energy Industry‖ category may employ a value of 1g of 

CH&ihel4;/mmBtu.
6. Proposed Amendments to Table AA-1 to 40 CFR part 98, subpart AA:

Table AA–1 to Subpart AA of Part 98—Kraft Pulping Liquor 

Emissions Factors for Biomass-Based CO2, CH4, and N2O

Wood furnish

Biomass-based emissions factors

(kg/mmBtu HHV)

CO2

a CH4 N2O

North American Softwood 94.4 0.030 0.0019 0.0050.00042

North American Hardwood 93.7 0.0019 0.00042

Bagasse 95.5 0.0019 0.00042

Bamboo 93.7 0.0019 0.00042

Straw 95.1 0.0019 0.00042

aIncludes emissions from both the recovery furnace and pulp mill lime 

kiln.

7. Proposed Amendments to Table AA-2 to 40 CFR part 98, subpart AA:

Table AA–2 to Subpart AA of Part 98—Kraft Lime Kiln and Calciner 

Emissions Factors for Fossil Fuel-Based CH&ihel4;CH4 and 

N&ihel2;ON2O

Fuel

Fossil fuel-based emissions factors (kg/mmBtu HHV)

Kraft lime kilns Kraft calciners

CH&ihel4;CH4 N&ihel2;ON2O CH&ihel4;CH4 N&ihel2;ON2O

Residual Oil

(any type)

0.0027 0 0.0027 0.0003

Distillate Oil

(any type)

0.0027 0 0.0027 0.0004

Natural Gas 0.0027 0 0.0027 0.0001

Biogas 0.0027 0 0.0027 0.0001

Petroleum coke 0.0027 0 NAa a

NAa

Other Fuels See Table 

C-2

0 See Table

C-2

See Table

C-2

aEmission factors for kraft calciners are not available.
8. Proposed Amendments to Table HH-1 to 40 CFR part 98, subpart HH:

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) 0.20 Weight 

fraction, wet 

basis.

k (precipitation plus 

recirculated leachatea<20 

inches/year)

0.02 yr−1

k (precipitation plus 

recirculated leachatea20–40 

inches/year)

0.038 yr−1

k (precipitation plus 

recirculated leachatea>40 

inches/year)

0.057 yr−1

DOC and k values—Modified bulk MSW option

DOC (bulk MSW, excluding inerts 

and C&D waste)

0.31 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 0.057b yr−1

k (inerts, e.g., glass, 

plastics, metal, concrete)

0.00 yr−1

k (C&D waste) 0.02 to 0.04b yr−1

DOC and k values—Waste composition option
Factor Default value Units

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.

k (food waste) 0.06 to 0.185c yr−1

k (garden) 0.05 to 0.10c yr−1

k (paper) 0.04 to 0.06c yr−1

k (wood and straw) 0.02 to 0.03c yr−1

k (textiles) 0.04 to 0.06c yr−1

k (diapers) 0.05 to 0.10c yr−1

k (sewage sludge) 0.06 to 0.185c yr−1

k (inerts e.g., glass, 0.00 yr−1
Factor Default value Units

plastics, metal, concrete)

Other parameters—All MSW landfills

MCF 1.

DOCF 0.5

F 0.5

OX 0.1See Table HH4 of this 

subpart

DE 0.99

aRecirculated 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 0.057 rather than calculating the 

recirculated leachate rate.

bUse 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.

cUse 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.

9. Proposed Amendments to Table HH-2 to 40 CFR part 98, subpart HH:
Table HH–2 to Subpart HH of Part 98—U.S. Per Capita Waste 

Disposal Rates

Year

Waste per capita

ton/cap/yr

% to 

SWDS

1950 0.63 100

1951 0.63 100

1952 0.63 100

1953 0.63 100

1954 0.63 100

1955 0.63 100

1956 0.63 100

1957 0.63 100

1958 0.63 100

1959 0.63 100

1960 0.63 100

1961 0.64 100

1962 0.64 100

1963 0.65 100

1964 0.65 100

1965 0.66 100

1966 0.66 100

1967 0.67 100

1968 0.68 100

1969 0.68 100

1970 0.69 100

1971 0.69 100

1972 0.70 100

1973 0.71 100

1974 0.71 100

1975 0.72 100

1976 0.73 100

1977 0.73 100

1978 0.74 100

1979 0.75 100

1980 0.75 100

1981 0.76 100

1982 0.77 100

1983 0.77 100

1984 0.78 100

1985 0.79 100

1986 0.79 100

1987 0.80 100

1988 0.80 100

1989 0.8583 84

1990 0.8482 77

Deleted Cells
Year

Waste per capita

ton/cap/yr

% to 

SWDS

1991 0.7876 76

1992 0.7674 72

1993 0.7876 71

1994 0.7775 67

1995 0.7270 63

1996 0.7168 62

1997 0.7269 61

1998 0.7875 61

1999 0.7875 60

2000 0.8480 61

2001 0.9591 63

2002 1.0602 66

2003 1.0602 65

2004 1.0601 64

2005 1.060.98 64

2006 1.060.95 64

2007 0.95

2008 0.95

2009 and all later years 0.95

Editorial Note: At 75 FR 66474, October 28, 2010, Table HH–2 to 

subpart HH was amended; however, the amendment could not be 

incorporated as instructed.

Deleted Cells
10. Proposed Table HH-4 to 40 CFR part 98, subpart HH:

Table HH–4 to Subpart HH of Part 98—Landfill Methane Oxidation 

Fractions

If your methane flux ratea for the 

reporting year is:

Use this landfill methane 

oxidation fraction:

Less than 10 grams per square 

meter per day (g/m2/d)

0.35

10 to 70 g/m2/d 0.25

Greater than 70 g/m2/d 0.10

aMethane flux rate (in grams per square meter per day; g/m2/d) is 

the mass flow rate of methane per unit area at the bottom of the 

surface soil prior to any oxidation and is calculated as 

follows. 

For Equation HH-5 of this subpart, or for Equation TT-6 of 

subpart TT of this part,

MF K G SArea CH4

For Equation HH-6 of this subpart,

MF K G - R SArea

1

CH4 n

N

n

For Equations HH-7 of this subpart,

SArea

f

R

CE

1 MF K

1 Rec,n

n

N

n

For Equation HH-8 of this subpart,

R SArea

f

R

CE

1 MF K

1

n

1 Rec,n

n

N

n

N

n

Where:

MF = Methane flux rate from the landfill in the reporting 

year (grams per square meter per day, g/m2/d).

K = unit conversion factor = 106/365 (g/metric ton per 

days/year) or 106/366 for a leap year.

Field Code Changed

Field Code Changed

Field Code Changed

Field Code Changed
SArea = The surface area of the landfill containing waste at 

the beginning of the reporting year (square meters, 

m

2). 

GCH4 = Modeled methane generation rate in reporting year from 

Equation HH–1 of this subpart, or, for application 

with Equation HH-6 only, the greater of the modeled 

methane generation rate in reporting year from 

Equation HH–1 of this subpart and the quantity of 

recovered CH4 from Equation HH–4 of this subpart 

(metric tons CH4).

CE = Collection efficiency estimated at landfill, taking 

into account system coverage, operation, and cover 

system materials from Table HH–3 of this subpart. If 

area by soil cover type information is not available, 

use default value of 0.75 (CE4 in table HH–3 of this 

subpart) for all areas under active influence of the 

collection system.

N = Number of landfill gas measurement locations 

(associated with a destruction device or gas sent offsite). If a single monitoring location is used to 

monitor volumetric flow and CH4 concentration of the 

recovered gas sent to one or multiple destruction 

devices, then N=1. 

Rn = Quantity of recovered CH4 from Equation HH–4 of this 

subpart for the nth measurement location (metric tons).

fRec,n = Fraction of hours the recovery system associated with 

the nth measurement location was operating (annual 

operating hours/8760 hours per year or annual 

operating hours/8784 hours per year for a leap year).

11. Proposed Amendments to Table MM-1 to 40 CFR part 98, subpart MM:
Table MM–1 to Subpart MM of Part 98—Default Factors for 

Petroleum Products and Natural Gas Liquids12

Products

Column A: 

density

(metric 

tons/bbl)

Column B:

carbon 

share

(% of 

mass)

Column C:

emission factor

(metric tons 

CO2/bbl)

Finished Motor Gasoline

Conventional—Summer

Regular 0.1181 86.66 0.3753

Midgrade 0.1183 86.63 0.3758

Premium 0.1185 86.61 0.3763

Conventional—Winter

Regular 0.1155 86.50 0.3663

Midgrade 0.1161 86.55 0.3684

Premium 0.1167 86.59 0.3705

Reformulated—Summer

Regular 0.1167 86.13 0.3686

Midgrade 0.1165 86.07 0.3677

Premium 0.1164 86.00 0.3670

Reformulated—Winter

Regular 0.1165 86.05 0.3676

Midgrade 0.1165 86.06 0.3676

Premium 0.1166 86.06 0.3679

Gasoline—Other 0.1185 86.61 0.3763

Blendstocks

CBOB—Summer

Regular 0.1181 86.66 0.3753

Midgrade 0.1183 86.63 0.3758

Premium 0.1185 86.61 0.3763

CBOB—Winter

Regular 0.1155 86.50 0.3663

Midgrade 0.1161 86.55 0.3684

Premium 0.1167 86.59 0.3705
Products

Column A: 

density

(metric 

tons/bbl)

Column B:

carbon 

share

(% of 

mass)

Column C:

emission factor

(metric tons 

CO2/bbl)

RBOB—Summer

Regular 0.1167 86.13 0.3686

Midgrade 0.1165 86.07 0.3677

Premium 0.1164 86.00 0.3670

RBOB—Winter

Regular 0.1165 86.05 0.3676

Midgrade 0.1165 86.06 0.3676

Premium 0.1166 86.06 0.3679

Blendstocks—Other 0.1185 86.61 0.3763

Oxygenates

Methanol 0.1268 37.48 0.1743

GTBA 0.1257 64.82 0.2988

MTBE 0.1181 68.13 0.2950

ETBE 0.1182 70.53 0.3057

TAME 0.1229 70.53 0.3178

DIPE 0.1156 70.53 0.2990

Distillate Fuel Oil

Distillate No. 1

Ultra Low Sulfur 0.1346 86.40 0.4264

Low Sulfur 0.1346 86.40 0.4264

High Sulfur 0.1346 86.40 0.4264

Distillate No. 2

Ultra Low Sulfur 0.1342 87.30 0.4296

Low Sulfur 0.1342 87.30 0.4296

High Sulfur 0.1342 87.30 0.4296

Distillate Fuel Oil No. 4 0.1452 86.47 0.4604

Residual Fuel Oil No. 5 (Navy 

Special)

0.1365 85.67 0.4288

Residual Fuel Oil No. 6 0.1528 84.67 0.4744
Products

Column A: 

density

(metric 

tons/bbl)

Column B:

carbon 

share

(% of 

mass)

Column C:

emission factor

(metric tons 

CO2/bbl)

(a.k.a. Bunker C)

Kerosene-Type Jet Fuel 0.1294 86.30 0.4095

Kerosene 0.1346 86.40 0.4264

Diesel—Other 0.1452 86.47 0.4604

Petrochemical Feedstocks

Naphthas (< 401 °F) 0.1158 84.11 0.3571

Other Oils (> 401 °F) 0.1390 87.30 0.4450

Unfinished Oils

Heavy Gas Oils 0.1476 85.80 0.4643

Residuum 0.1622 85.70 0.5097

Other Petroleum Products and Natural Gas Liquids

Aviation Gasoline 0.1120 85.00 0.3490

Special Naphthas 0.1222 84.76 0.3798

Lubricants 0.1428 85.80 0.4492

Waxes 0.1285 85.30 0.4019

Petroleum Coke 0.1818 92.28 0.6151

Asphalt and Road Oil 0.1634 83.47 0.5001

Still Gas 0.1405 77.70 0.4003

Ethane3 0.08660579 79.89 0.2537170

Ethylene4 0.09030492 85.63 0.2835154

Propane3 0.07840806 81.71 0.2349241

Propylene3 0.08030827 85.63 0.2521260

Butane3 0.09110928 82.66 0.2761281

Butylene3 0.09350972 85.63 0.2936305

Isobutane3 0.08760892 82.66 0.2655270

Isobutylene3 0.09360949 85.63 0.2939298

Pentanes Plus 0.1055 83.63 0.3235

Miscellaneous Products 0.1380 85.49 0.4326
1In the case of products blended with some portion of biomassbased fuel, the carbon share in Table MM–1 of this subpart 

represents only the petroleum-based components.

2Products that are derived entirely from biomass should not be 

reported, but products that were derived from both biomass and a 

petroleum product (i.e., co-processed) should be reported as the 

petroleum product that it most closely represents.

3The density and emission factors for components of LPG 

determined at 60oF and saturation pressure (LPGs other than 

ethylene)

4The density and emission factor for ethylene determined at 41oF 

and saturation pressure.

12. Proposed Amendments to Table NN-1 to 40 CFR part 98, subpart NN:

Table NN–1 to Subpart HHNN of Part 98—Default Factors for 

Calculation Methodology 1 of This Subpart

Fuel

Default highhigher heating value 

factorvalue1

Default CO2

emission 

factor

(kg CO2/MMBtu)

Natural Gas 1.028026 MMBtu/Mscf 53.0206

Propane 3.8223.84 MMBtu/bbl 61.4662.87

Normal 

butane

4.2424.34 MMBtu/bbl 65.1564.77

Ethane 4.0322.85 MMBtu/bbl 62.6459.60

Isobutane 4.07416 MMBtu/bbl 64.9164.94

Pentanes 

plus

4.620 MMBtu/bbl 70.02

1 Conditions for higher heating values presented in MMBtu/bbl are 60oF and saturation pressure.

13. Proposed Amendments to Table NN-2 to 40 CFR part 98, subpart NN:

Table NN–2 to Subpart HHNN of Part 98—Lookup Default Values for 

Calculation Methodology 2 of This Subpart

Fuel Unit

Default CO2

emission value

(MT CO2/Unit) 1

Natural Gas Mscf 0.0550544

Propane Barrel 0.235241
Fuel Unit

Default CO2

emission value

(MT CO2/Unit) 1

Normal butane Barrel 0.276281

Ethane Barrel 0.253170

Isobutane Barrel 0.266270

Pentanes plus Barrel 0.324

1 Conditions for emission value presented in MT CO2/bbl are 60oF and saturation pressure.

14. Proposed Amendments to Table TT-1 to 40 CFR part 98, subpart TT:

Table TT–1 to Subpart TT—Default DOC and Decay Rate Values for 

Industrial Waste Landfills

Industry/Waste Type

DOC

(weight 

fraction, 

wet basis)

k

[dry 

climatea]

(yr−1)

k

[moderate 

climatea]

(yr−1)

k

[wet 

climatea]

(yr−1)

Food Processing

(other than sludge)

0.22 0.06 0.12 0.18

Pulp and Paper (other 

than sludge)

0.20 0.02 0.03 0.04

Wood and Wood Product

(other than sludge) 

0.43 0.02 0.03 0.04

Construction and 

Demolition

0.08 0.02 0.03 0.04

Industrial Sludge 0.09 0.02 0.04 0.06

Inert Waste [i.e.,

wastes listed in 

§98.460(c)(2)]

0 0 0 0

Other Industrial 

Solid Waste (not 

otherwise listed)

0.20 0.02 0.04 0.06

aThe applicable climate classification is determined based on the annual 

rainfall plus the recirculated leachate application rate. Recirculated 

leachate application rate (in inches/year) is the total volume of leachate 

recirculated from company records or engineering estimates and applied to the 
landfill divided by the area of the portion of the landfill containing waste 

[with appropriate unit conversions].

(1) Dry climate = precipitation plus recirculated leachate 

less than 20 inches/year

(2) Moderate climate = precipitation plus recirculated 

leachate from 20 to 40 inches/year (inclusive)

(3) Wet climate = precipitation plus recirculated leachate 

greater than 40 inches/year

Alternatively, landfills that use leachate recirculation 

can elect to use the k value for wet climate rather than 

calculating the recirculated leachate rate.

(1) Dry climate = precipitation plus recirculated leachate 

less than 20 inches/year.