(cc) If you elect to delay reporting the information in paragraph (g)(5)(i), (g)(5)(ii), (g)(5)(iii)(A), (g)(5)(iii)(B), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(v), (l)(2)(v), (l)(3)(iv), (l)(4)(iv), (m)(5), or (m)(6) of this section, you must report the information required in that paragraph no later than the date 2 years following the date specified in § 98.3(b) introductory text.
 Amend § 98.238 by:
a. Adding a definition for "Centralized oil production site" in alphabetical order;
b. Revising the definitions for "Compressor mode" and "Compressor source;"
c. Adding a definition for "Compressor station" in alphabetical order;
d. Removing the second definition for "Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements;"
e. Revising the definitions for "Flare stack emissions" and "Forced extraction of natural gas liquids;" and
f. Adding definitions for "Other large release event," "Routed to combustion," "Well blowout," and "Well release" in alphabetical order.
The revisions and additions read as follows:
§ 98.238 Definitions.
*	*	*	*	*
Centralized oil production site means any permanent combination of one or more hydrocarbon liquids storage tanks located on one or more contiguous or adjacent properties that does not also contain a permanent combination of one or more compressors that are part of the onshore petroleum and natural gas gathering and boosting facility that gathers hydrocarbon liquids from multiple well-pads.
*	*	*	*	*
Compressor mode means the operational and pressurized status of a compressor. For both centrifugal compressors and reciprocating compressors, "mode" refers to either: Operating-mode, standby-pressurized-mode, or not-operating-depressurized-mode.
Compressor source means the source of certain venting or leaking emissions from a centrifugal or reciprocating compressor. For centrifugal compressors, "source" refers to blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind flanges, wet seal oil degassing vents, and dry seal vents. For reciprocating compressors, "source" refers to blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind flanges, and rod packing emissions.
Compressor station means any permanent combination of one or more compressors located on one or more contiguous or adjacent properties that are part of the onshore petroleum and natural gas gathering and boosting facility that move natural gas at increased pressure through gathering pipelines or into or out of storage.
*	*	*	*	*
Flare stack emissions means CO2 in gas routed to a flare, CO2 from partial combustion of hydrocarbons in gas routed to a flare, CH4 emissions resulting from the incomplete combustion of hydrocarbons in gas routed to a flare, and N2O resulting from operation of a flare.
Forced extraction of natural gas liquids means removal of ethane or higher carbon number hydrocarbons existing in the vapor phase in natural gas, by removing ethane or heavier hydrocarbons derived from natural gas into natural gas liquids by means of a forced extraction process. Forced extraction processes include but are not limited to refrigeration, absorption (lean oil), cryogenic expander, and combinations of these processes. Forced extraction does not include natural gas dehydration, the collection or gravity separation of water or hydrocarbon liquids from natural gas at ambient temperature or heated above ambient temperatures, the condensation of water or hydrocarbon liquids through passive reduction in pressure or temperature, a Joule-Thomson valve, a dew point depression valve, or an isolated or standalone Joule-Thomson skid.
*	*	*	*	*
Other large release event means an unplanned, unexpected, and uncontrolled release to the atmosphere of gas, liquids, or mixture thereof, from wells and/or other equipment that result in emissions for which there are no methodologies in § 98.233 to appropriately estimate these emissions. Other large release events include, but are not limited to, well blowouts, well releases, pressure relief valve releases from process equipment other than onshore production and onshore petroleum and natural gas gathering and boosting storage tanks, and releases that occur as a result of an accident, equipment rupture, fire, or explosion. Other large release events also include failure of equipment or equipment components such that a single equipment leak or release has emissions that exceed the emissions calculated for that source using applicable methods in § 98.233 by the threshold in § 98.233(y).
*	*	*	*	*
Routed to combustion means, for onshore petroleum and natural gas production facilities, natural gas distribution facilities, and onshore petroleum and natural gas gathering and boosting facilities, that emissions are routed to stationary or portable fuel combustion equipment specified in § 98.232(c)(22), (i)(7), or (j)(12), as applicable. For all other industry segments in this subpart, routed to combustion means that emissions are routed to a stationary fuel combustion unit subject to subpart C of this part (General Stationary Fuel Combustion Sources).
*	*	*	*	*
Well blowout means a complete loss of well control for a long duration of time resulting in an emissions release.
*	*	*	*	*
Well release means a short duration of uncontrolled emissions release from a well followed by a period of controlled emissions release in which control techniques were successfully implemented.
*	*	*	*	*
  Revise Table W-1A to subpart W of part 98 to read as follows:
Table W-1A to Subpart W of Part 98 -- Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production Facilities and Onshore Petroleum and Natural Gas Gathering and Boosting Facilities
Onshore petroleum and natural gas production and Onshore petroleum and natural gas gathering and boosting
Emission factor (scf/hour/
component)
Population Emission Factors -- Pneumatic Device Vents and Pneumatic Pumps, Gas Service1
Continuous Low Bleed Pneumatic Device Vents2
6.8
Continuous High Bleed Pneumatic Device Vents2
21.2
Intermittent Bleed Pneumatic Device Vents2
8.8
Pneumatic Pumps3
13.3
Population Emission Factors -- Major Equipment, Gas Service
Wellhead
0.59
Separator
0.84
Meters/Piping
2.8
Compressor
10
Acid Gas Removal Unit
2.4
Dehydrator
3.1
Heater Treater
0.12
Storage Vessel
0.85
Population Emission Factors -- Major Equipment, Crude Service
Wellhead
0.14
Separator
0.43
Meters/Piping
2.5
Compressor
10
Acid Gas Removal Unit
2.4
Dehydrator
3.1
Heater Treater
0.35
Storage Vessel
0.56
Population Emission Factors -- Gathering Pipelines by Material Type4
Protected Steel
0.91
Unprotected Steel
8.0
Plastic/Composite
0.27
Cast Iron
8.2
1 For multi-phase flow that includes gas, use the gas service emission factors.
2 Emission factor is in units of "scf/hour/device."
3 Emission factor is in units of "scf/hour/pump."
4 Emission factors are in units of "scf/hour/mile of pipeline."

 Revise the title of Table W-1B to subpart W of part 98 to read as follows: "Table W-1B to Subpart W of Part 98 -- Default Average Component Counts for Major Onshore Natural Gas Production Equipment and Onshore Petroleum and Natural Gas Gathering and Boosting Equipment for Reporting Year 2022 and Prior Reporting Years".
 Revise the title of Table W-1C to subpart W of part 98 to read as follows: "Table W-1C to Subpart W of Part 98 -- Default Average Component Counts For Major Crude Oil Production Equipment for Reporting Year 2022 and Prior Reporting Years".
 Revise the title of Table W-1D to subpart W of part 98 to read as follows: "Table W-1D to Subpart W of Part 98 -- Designation Of Eastern And Western U.S. for Reporting Year 2022 and Prior Reporting Years".
 Revise Table W-1E to subpart W of part 98 to read as follows:
Table W-1E to Subpart W of Part 98 --  Default Whole Gas Leaker Emission Factors for Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting
Equipment components
Emission factor (scf/hour/component)

If you survey using Method 21 as specified in § 98.234(a)(2)(i)
If you survey using Method 21 as specified in § 98.234(a)(2)(ii)
If you survey using any of the methods in § 98.234(a)(1), (3), or (5)
Leaker Emission Factors -- All Components, Gas Service1
Valve
4.9
3.5
16
Flange
4.1
2.2
11
Connector (other)
1.3
0.8
7.9
Open-Ended Line2
2.8
1.9
10
Pressure Relief Valve
4.5
2.8
13
Pump Seal
3.7
1.4
23
Other3
4.5
2.8
15
Leaker Emission Factors -- All Components, Oil Service
Valve
3.2
2.2
9.2
Flange
2.7
1.4
11
Connector (other)
1.0
0.6
9.1
Open-Ended Line
1.6
1.1
6.6
Pump4
3.7
2.6
15
Other3
3.1
2.0
2.9
1 For multi-phase flow that includes gas, use the gas service emission factors.
2 The open-ended lines component type includes blowdown valve and isolation valve leaks emitted through the blowdown vent stack for centrifugal and reciprocating compressors.
3 "Others" category includes any equipment leak emission point not specifically listed in this table, as specified in § 98.232(c)(21) and (j)(10).
4 The pumps component type in oil service includes agitator seals.

  Remove Table W-2 to subpart W of part 98 and add Table W-2A and Table W-2B to subpart W of part 98 in numerical order to read as follows:
Table W-2A to Subpart W of Part 98 -- Default Total Hydrocarbon Leaker Emission Factors for Onshore Natural Gas Processing
Onshore natural gas processing plants
Emission factor (scf/hour/component)

If you survey using Method 21 as specified in § 98.234(a)(2)(i)
If you survey using Method 21 as specified in § 98.234(a)(2)(ii)
If you survey using any of the methods in § 98.234(a)(1), (3), or (5)
Leaker Emission Factors -- Compressor Components, Gas Service
Valve1
14.84
9.51
61
Connector
5.59
3.58
23
Open-Ended Line
17.27
11.07
71
Pressure Relief Valve
39.66
25.42
163
Meter
19.33
12.39
79
Other2
4.1
2.63
17
Leaker Emission Factors -- Non-Compressor Components, Gas Service
Valve1
6.42
4.12
26
Connector
5.71
3.66
23
Open-Ended Line
11.27
7.22
46
Pressure Relief Valve
2.01
1.29
8.2
Meter
2.93
1.88
12
Other2
4.1
2.63
17
1 Valves include control valves, block valves and regulator valves.
2 Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table.

Table W-2B to Subpart W of Part 98 -- Default Whole Gas Population Emission Factors for Onshore Natural Gas Processing
Population emission factors -- gas service onshore natural gas processing
Emission factor (scf whole gas/hour/device)
Continuous Low Bleed Pneumatic Device Vents
6.8
Continuous High Bleed Pneumatic Device Vents
32.4
Intermittent Bleed Pneumatic Device Vents
2.3

 Revise Table W-3A to subpart W of part 98 to read as follows:
Table W-3A to Subpart W of Part 98 -- Default Total Hydrocarbon Leaker Emission Factors for Onshore Natural Gas Transmission Compression
Onshore natural gas transmission compression
Emission factor (scf/hour/component)

If you survey using Method 21 as specified in § 98.234(a)(2)(i)
If you survey using Method 21 as specified in § 98.234(a)(2)(ii)
If you survey using any of the methods in § 98.234(a)(1), (3), or (5)
Leaker Emission Factors -- Compressor Components, Gas Service
Valve1
14.84
9.51
61
Connector
5.59
3.58
23
Open-Ended Line
17.27
11.07
71
Pressure Relief Valve
39.66
25.42
163
Meter or Instrument
19.33
12.39
79
Other2
4.1
2.63
17
Leaker Emission Factors -- Non-Compressor Components, Gas Service
Valve1
6.42
4.12
26
Connector
5.71
3.66
23
Open-Ended Line
11.27
7.22
46
Pressure Relief Valve
2.01
1.29
8.2
Meter or Instrument
2.93
1.88
12
Other2
4.1
2.63
17
1 Valves include control valves, block valves and regulator valves.
2 Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table, as specified in § 98.232(e)(8).

 Revise Table W-3B to subpart W of part 98 to read as follows:
Table W-3B to Subpart W of Part 98 -- Default Whole Gas Population Emission Factors for Onshore Natural Gas Transmission Compression
Population emission factors -- gas service onshore natural gas transmission compression
Emission factor (scf whole gas/hour/device)
Continuous Low Bleed Pneumatic Device Vents
6.8
Continuous High Bleed Pneumatic Device Vents
32.4
Intermittent Bleed Pneumatic Device Vents
2.3

 12. Revise Table W-4A to subpart W of part 98 to read as follows:
Table W-4A to Subpart W of Part 98 -- Default Total Hydrocarbon Leaker Emission Factors for Underground Natural Gas Storage
Underground natural gas storage
Emission factor (scf/hour/component)

If you survey using Method 21 as specified in § 98.234(a)(2)(i)
If you survey using Method 21 as specified in § 98.234(a)(2)(ii)
If you survey using any of the methods in § 98.234(a)(1), (3), or (5)
Leaker Emission Factors -- Storage Station, Gas Service
Valve1
14.84
9.51
61
Connector (other)
5.59
3.58
23
Open-Ended Line
17.27
11.07
71
Pressure Relief Valve
39.66
25.42
163
Meter and Instrument
19.33
12.39
79
Other2
4.1
2.63
17
Leaker Emission Factors -- Storage Wellheads, Gas Service
Valve1
4.5
3.2
18
Connector (other than flanges)
1.2
0.7
4.9
Flange
3.8
2.0
16
Open-Ended Line
2.5
1.7
10
Pressure Relief Valve
4.1
2.5
17
Other2
4.1
2.5
17
1 Valves include control valves, block valves and regulator valves.
2 Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table, as specified in § 98.232(f)(6) and (8).

 Revise Table W-4B to subpart W of part 98 to read as follows:
Table W-4B to Subpart W of Part 98 -- Default Population Emission Factors for Underground Natural Gas Storage
Underground natural gas storage
Emission factor (scf/hour/component)
Total Hydrocarbon Population Emission Factors -- Storage Wellheads, Gas Service
Connector
0.01
Valve
0.1
Pressure Relief Valve
0.17
Open-Ended Line
0.03
Whole Gas Population Emission Factors -- Other Components, Gas Service
Continuous Low Bleed Pneumatic Device Vents[1]
6.8
Continuous High Bleed Pneumatic Device Vents[1]
32.4
Intermittent Bleed Pneumatic Device Vents[1]
2.3
1 Emission Factor is in units of "scf whole gas/hour/device."

 Revise Table W-5A to subpart W of part 98 to read as follows:
Table W-5A to Subpart W of Part 98 -- Default Methane Leaker Emission Factors for Liquefied Natural Gas (LNG) Storage
LNG storage
Emission factor (scf/hour/component)

If you survey using Method 21 as specified in § 98.234(a)(2)(i)
If you survey using Method 21 as specified in § 98.234(a)(2)(ii)
If you survey using any of the methods in § 98.234(a)(1), (3), or (5)
Leaker Emission Factors -- LNG Storage Components, LNG Service
Valve
1.19
0.23
4.9
Pump Seal
4.00
0.73
16
Connector
0.34
0.11
1.4
Other1
1.77
0.99
7.3
Leaker Emission Factors -- LNG Storage Components, Gas Service
Valve2
14.84
9.51
61
Connector
5.59
3.58
23
Open-Ended Line
17.27
11.07
71
Pressure Relief Valve
39.66
25.42
163
Meter and Instrument
19.33
12.39
79
Other3
4.1
2.63
17
1 "Other" equipment type for components in LNG service should be applied for any equipment type other than connectors, pumps, or valves.
2 Valves include control valves, block valves and regulator valves.
3 "Other" equipment type for components in gas service should be applied for any equipment type other than valves, connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, as specified in § 98.232(g)(6) and (7).

 Revise Table W-6A to subpart W of part 98 to read as follows:
Table W-6A to Subpart W of Part 98 -- Default Methane Leaker Emission Factors for LNG Import and Export Equipment
LNG import and export equipment
Emission factor (scf/hour/component)

If you survey using Method 21 as specified in § 98.234(a)(2)(i)
If you survey using Method 21 as specified in § 98.234(a)(2)(ii)
If you survey using any of the methods in § 98.234(a)(1), (3), or (5)
Leaker Emission Factors -- LNG Terminals Components, LNG Service
Valve
1.19
0.23
4.9
Pump Seal
4.00
0.73
16.
Connector
0.34
0.11
1.4
Other1
1.77
0.99
7.3
Leaker Emission Factors -- LNG Terminals Components, Gas Service
Valve2
14.84
9.51
61
Connector
5.59
3.58
23
Open-Ended Line
17.27
11.07
71
Pressure Relief Valve
39.66
25.42
163
Meter and Instrument
19.33
12.39
79
Other3
4.1
2.63
17
1 "Other" equipment type for components in LNG service should be applied for any equipment type other than connectors, pumps, or valves.
2 Valves include control valves, block valves and regulator valves.
3 "Other" equipment type for components in gas service should be applied for any equipment type other than valves, connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, as specified in § 98.232(h)(7) and (8).

 Remove Table W-7 to subpart W of part 98 and add Table W-7A and Table W-7B to subpart W of part 98 in numerical order to read as follows:
Table W-7A to Subpart W of Part 98 -- Default Total Hydrocarbon Leaker Emission Factors for Onshore Natural Gas Processing
Natural gas distribution
Emission factor (scf/hour/component)

If you survey using Method 21 as specified in § 98.234(a)(2)(i)
If you survey using any of the methods in § 98.234(a)(1), (3), or (5)
Leaker Emission Factors -- Transmission-Distribution Transfer Station1 Components, Gas Service
Connector
1.69
6.7
Block Valve
0.557
2.3
Control Valve
9.34
38
Pressure Relief Valve
0.27
1.1
Orifice Meter
0.212
0.87
Regulator
0.772
3.2
Open-ended Line
26.131
107
1 Excluding customer meters.

Table W-7B to Subpart W of Part 98 -- Default Methane Population Emission Factors for Natural Gas Distribution
Natural gas distribution
Emission factor (scf/hour/component)
Population Emission Factors -- Below Grade Transmission-Distribution Transfer Station Components and Below Grade Metering-Regulating Station1 Components, Gas Service2
Below Grade T-D Transfer Station
0.30
Below Grade M&R Station
0.30
Population Emission Factors -- Distribution Mains, Gas Service3
Unprotected Steel
1.2
Protected Steel
2.3
Plastic
0.45
Cast Iron
2.8
Population Emission Factors -- Distribution Services, Gas Service4
Unprotected Steel
0.086
Protected Steel
0.0077
Plastic
0.0016
Copper
0.03
1 Excluding customer meters.
2 Emission Factor is in units of "scf/hour/station."
3 Emission Factor is in units of "scf/hour/mile."
4 Emission Factor is in units of "scf/hour/number of services."

 Add Table W-8 to subpart W of part 98 to read as follows:
Table W-8 to Subpart W of Part 98 -- Default Methane Emission Factors for Natural Gas-Fired Compressor-Drivers
Compressor-Driver Engine Design Class
Emission factor (kg CH4/mmBtu)
2-stroke lean-burn
0.658
4-stroke lean-burn
0.522
4-stroke rich-burn
0.045

Subpart X -- Petrochemical Production
 Amend § 98.243 by revising paragraphs (b)(3) and (d)(5) to read as follows:
§ 98.243 Calculating GHG emissions.
*	*	*	*	*
(b) *	*	*
(3) For each flare, calculate CO2, CH4, and N2O emissions using the methodology specified in § 98.253(b).
*	*	*	*	*
(d) *	*	*
(5) For each flare, calculate CO2, CH4, and N2O emissions using the methodology specified in § 98.253(b).
 Amend § 98.244 by revising paragraph (b)(4)(iii) to read as follows:
§ 98.244 Monitoring and QA/QC requirements.
*	*	*	*	*
(b) *	*	*
(4) *	*	*
(iii) ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography (incorporated by reference, see § 98.7).
*	*	*	*	*
 Amend § 98.246 by revising paragraphs (a) introductory text, (a)(2) and (5), (a)(13) and (15), (b)(7) and (8), (c) introductory text, (c)(3) and (4), and adding paragraph (c)(6) to read as follows:
§ 98.246 Data reporting requirements.
*	*	*	*	*
(a) If you use the mass balance methodology in § 98.243(c), you must report the information specified in paragraphs (a)(1) through (15) of this section for each type of petrochemical produced, reported by process unit.
*	*	*	*	*
(2) The type of petrochemical produced.
*	*	*	*	*
(5) Annual quantity of each type of petrochemical produced from each process unit (metric tons). If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, the portion of the total amount of EDC produced that is used in VCM production may be a measured quantity or an estimate that is based on process knowledge and best available data. The portion of the total amount of EDC produced that is not utilized in VCM production must be measured in accordance with § 98.244(b)(2) or (3). Sum the amount of EDC used in the production of VCM plus the amount of separate EDC product to report as the total quantity of EDC petrochemical from an integrated EDC/VCM petrochemical process unit.
*	*	*	*	*
(13) Name and annual quantity (in metric tons) of each product included in Equations X-1, X-2, and X-3 of § 98.243. If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, the reported quantity of EDC product should include only that which was not used in the VCM process.
*	*	*	*	*
(15) For each gaseous feedstock or product for which the volume was used in Equation X-1, report the annual average molecular weight of the measurements or determinations, conducted according to § 98.243(c)(3) or (4). Report the annual average molecular weight in units of kg per kg mole.
(b) *	*	*
(7) Information listed in § 98.256(e) of subpart Y of this part for each flare that burns process off-gas. Additionally, provide estimates based on engineering judgment of the fractions of the total CO2, CH4 and N2O emissions that are attributable to combustion of off-gas from the petrochemical process unit(s) served by the flare.
(8) Annual quantity of each type of petrochemical produced from each process unit (metric tons).
*	*	*	*	*
(c) If you comply with the combustion methodology specified in § 98.243(d), you must report under this subpart the information listed in paragraphs (c)(1) through (c)(6) of this section.
*	*	*	*	*
(3) Information listed in § 98.256(e) of subpart Y of this part for each flare that burns ethylene process off-gas. Additionally, provide estimates based on engineering judgment of the fractions of the total CO2, CH4 and N2O emissions that are attributable to combustion of off-gas from the ethylene process unit(s) served by the flare.
(4) Name and annual quantity of each carbon-containing feedstock (metric tons).
*	*	*	*	*
(6) Name and annual quantity (in metric tons) of each product produced in each process unit.

Subpart Y -- Petroleum Refineries
 Amend § 98.253 by:
a. Revising the introductory text of paragraphs (b), (c), and (e);
b. Revising Equation Y-18b in paragraph (i)(2);
c. Revising parameters "Mwater" and "Hwater" of Equation Y-18b in paragraph (i)(2);
d. Adding parameter "fcoke" to Equation Y-18b in paragraph (i)(2); and
e. Revising parameter "Msteam" of Equation Y-18f in paragraph (i)(5).
The revisions and addition read as follows:
§ 98. 253 Calculating GHG emissions.
*	*	*	*	*
(b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) through (3) of this section. All gas discharged through the flare stack must be included in the flare GHG emissions calculations with the exception of the following, which may be excluded as applicable: 1) gas used for the flare pilots, and 2) if using the calculation method in paragraph (b)(1)(iii) of this section, the gas released during start-up, shutdown, or malfunction events of 500,000 scf/day or less.
*	*	*	*	*
 (c) For catalytic cracking units and traditional fluid coking units, calculate the GHG emissions from coke burn-off using the applicable methods described in paragraphs (c)(1) through (c)(5) of this section.
*	*	*	*	*
 (e) For catalytic reforming units, calculate the CO2 emissions from coke burn-off using the applicable methods described in paragraphs (e)(1) through (e)(3) of this section and calculate the CH4 and N2O emissions using the methods described in paragraphs (c)(4) and (c)(5) of this section, respectively.
*	*	*	*	*
(i) *	*	*
(2) *	*	*
	Mwater=ρwaterxHwaterxPIxD24-fcokexMcokeρparticle	(Eq. Y-18b)
*	*	*	*	*
Mwater	=	Mass of water in the delayed coking unit vessel at the end of the cooling cycle just prior to atmospheric venting or draining (metric tons/cycle).
*	*	*	*	*
Hwater	=	Typical distance from the bottom of the coking unit vessel to the top of the water level at the end of the cooling cycle just prior to atmospheric venting or draining (feet) from company records or engineering estimates.
fcoke	=	Fraction of the coke-filled bed that is covered by water at the end of the cooling cycle just prior to atmospheric venting or draining. Use 1 if the water fully covers coke-filled portion of the coke drum.
*	*	*	*	*
(5) *	*	*
*	*	*	*	*
Msteam	=	Mass of steam generated and released per decoking cycle (metric tons/cycle) as determined in paragraph (i)(4) of this section.
*	*	*	*	*
 Amend § 98.254 by revising paragraph (d) introductory text and paragraph (e) introductory text to read as follows:
§ 98.254 Monitoring and QA/QC requirements.
*	*	*	*	*
(d) Except as provided in paragraph (g) of this section, determine gas composition and, if required, average molecular weight of the gas using any of the following methods. Alternatively, the results of chromatographic or direct mass spectrometer analysis of the gas may be used, provided that the gas chromatograph or mass spectrometer is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph or mass spectrometer are documented in the written Monitoring Plan for the unit under § 98.3(g)(5).
*	*	*	*	*
(e) Determine flare gas higher heating value using any of the following methods. Alternatively, the results of chromatographic analysis of the gas may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph are documented in the written Monitoring Plan for the unit under § 98.3(g)(5).
*	*	*	*	*
 Amend § 98.256 by revising paragraph (k)(6) to read as follows:
§ 98.256 Data reporting requirements.
*	*	*	*	*
(k) *	*	*
(6) The basis for the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (mass measurements from company records or calculated using Equation Y-18a of this subpart). If you use mass measurements from company records to determine the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle, you must also report:
(i) Internal height of delayed coking unit vessel (feet) for each delayed coking unit.
(ii) Typical distance from the top of the delayed coking unit vessel to the top of the coke bed (i.e., coke drum outage) at the end of the coking cycle (feet) from company records or engineering estimates for each delayed coking unit.
*	*	*	*	*
 Amend § 98.257 by revising paragraphs (b)(45), (46), and (53) and removing and reserving paragraphs (b)(54), (55), and (56) to read as follows:
§ 98.257 Records that must be retained.
*	*	*	*	*
(b) *	*	*
(45) Mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to atmospheric venting or draining (metric ton/cycle) (Equations Y-18b and Y-18e in § 98.253) for each delayed coking unit.
(46) Typical distance from the bottom of the coking unit vessel to the top of the water level at the end of the cooling cycle just prior to atmospheric venting or draining (feet) from company records or engineering estimates (Equation Y-18b in § 98.253) for each delayed coking unit.
*	*	*	*	*
(53) Fraction of the coke-filled bed that is covered by water at the end of the cooling cycle just prior to atmospheric venting or draining (Equation Y-18b in § 98.253) for each delayed coking unit.
*	*	*	*	*

Subpart BB --  Silicon Carbide Production
 Amend § 98.286 by revising the introductory text and adding paragraph (c) to read as follows:
§ 98.286 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, and paragraph (c) of this section, as applicable for each silicon carbide production facility.
*	*	*	*	*
(c) If methane abatement technology is used at the silicon carbide production facility, you must report the information in paragraphs (c)(1) through (3) of this section. Upon reporting this information once in an annual report, you are not required to report this information again unless the information changes during a reporting year, in which case, the reporter must include any updates in the annual report for the reporting year in which the change occurred.
(1) Type of methane abatement technology used on each silicon carbide process unit or production furnace, and date of installation for each.
(2) Methane destruction efficiency for each methane abatement technology (percent destruction). You must either use the manufacturer's specified destruction efficiency or the destruction efficiency determined via a performance test. If you report the destruction efficiency determined via a performance test, you must also report the test method that was used during the performance test.
(3) Percentage of annual operating hours that methane abatement technology was in use for all silicon carbide process units or production furnaces combined.
 Amend § 98.287 by revising the introductory text and adding paragraph (d) to read as follows:
§ 98.287 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each silicon carbide production facility.
*	*	*	*	*
(d) Records of all information reported as required under § 98.286(c).

Subpart DD --  Electrical Transmission and Distribution Equipment Use
 Amend § 98.300 by revising paragraph (a) introductory text and paragraphs (a)(3) and (7) to read as follows:
§ 98.300 Definition of the source category.
(a) The electrical transmission and distribution equipment use source category consists of all electric transmission and distribution equipment and servicing inventory insulated with or containing fluorinated GHGs, including but not limited to sulfur hexafluoride (SF6) and perfluorocarbons (PFCs), used within an electric power system. Electric transmission and distribution equipment and servicing inventory includes, but is not limited to:
*	*	*	*	*
(3) Switchgear, including closed-pressure and hermetically sealed-pressure switchgear and gas-insulated lines containing fluorinated GHGs, including but not limited to SF6 and PFCs.
*	*	*	*	*
(7) Other containers of fluorinated GHG, including but not limited to SF6 and PFCs.
 Revise § 98.301 to read as follows:
§ 98.301 Reporting threshold.
(a) You must report GHG emissions under this subpart if you are an electric power system as defined in § 98.308 and your facility meets the requirements of § 98.2(a)(1). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO2e per year emission threshold in Table A-3, you must calculate emissions of each fluorinated GHG, including but not limited to SF6 and PFCs, and then sum the emissions of each fluorinated GHG resulting from the use of electrical transmission and distribution equipment for threshold applicability purposes using equation DD-1 of this subpart.
	E=jiNCEPS,j*GHGi,w*GWPi* EF*0.000453592	(Eq. DD-1)
Where:
E	=	Annual emissions for threshold applicability purposes (metric tons CO2e).
NCEPS,j	=	the total nameplate capacity of insulating gas j-containing equipment (excluding hermetically sealed-pressure equipment) located within the facility plus the total nameplate capacity of insulting gas j-containing equipment (excluding hermetically sealed-pressure equipment) that is not located within the facility but is under common ownership or control
GHGi,w	=	The weight fraction of fluorinated GHG i in insulating gas j in the gas insulated equipment included in the total nameplate capacity NCEPS,j, expressed as a decimal fraction. If fluorinated GHG i is not part of a gas mixture, use a value of 1.0.
GWPi	=	Gas-appropriate GWP as provided in Table A-1 to subpart A of this part.
EF	=	Emission factor for electrical transmission and distribution equipment (lbs emitted/lbs nameplate capacity). For all gases, use an emission factor or 0.1.
I	=	fluorinated GHG contained in the electrical transmission and distribution equipment.
0.000453592	 =	conversion factor from lbs to metric tons.
(b) A facility other than an electric power system that is subject to this part because of emissions from any other source category listed in Table A-3 or A-4 in subpart A of this part is not required to report emissions under subpart DD of this part unless the total estimated emissions from fluorinated gas, including but not limited to SF6 and PFCs, containing equipment located at the facility, as calculated in equation DD-2 for comparison to the 25,000 metric ton CO2e per year emission threshold in Table A-3 meets or exceeds 25,000 tons CO2e.
	E=jiNCother,j*GHGi,w *GWPi* EF*0.000453592 	(Eq. DD-2)
Where:
E	=	Annual emissions for threshold applicability purposes (metric tons CO2e).
NCother,j	=	For a facility other than an electric power system, the total nameplate capacity of insulating gas j containing equipment (excluding hermetically sealed-pressure equipment) located within the facility
GHGi,w	=	The weight fraction of fluorinated GHG i in insulating gas j in the gas insulated equipment included in the total nameplate capacity NCother,j, expressed as a decimal fraction. If fluorinated GHG i is not part of a gas mixture, use a value of 1.0.
GWPi	=	Gas-appropriate GWP as provided in Table A-1 to subpart A of this part.
EF	=	Emission factor for electrical transmission and distribution equipment (lbs emitted/lbs nameplate capacity). For all gases, use an emission factor or 0.1.
I	=	fluorinated GHG contained in the electrical transmission and distribution equipment.
0.000453592	 =	conversion factor from lbs to metric tons.
 Revise § 98.302 to read as follows:
§ 98.302 GHGs to report.
You must report emissions of each fluorinated GHG, including but not limited to SF6 and PFC, from your facility (including emissions from fugitive equipment leaks, installation, servicing, equipment decommissioning and disposal, and from storage cylinders) resulting from the transmission and distribution servicing inventory and equipment listed in § 98.300(a). For acquisitions of equipment containing or insulated with fluorinated GHG, you must report emissions from the equipment after the title to the equipment is transferred to the electric power transmission or distribution entity.
 Revise § 98.303 to read as follows:
§ 98.303 Calculating GHG emissions.
(a) Calculate the annual emissions of each fluorinated GHG (including but not limited to SF6 and PFC) using the mass-balance approach in Equation DD-3 of this section:
User Emissionsi = GHGi,w * [(Decrease in Insulating gas j Inventory) + (Acquisitions of Insulating gas j)  -  (Disbursements of Insulating gas j)  -  (Net Increase in Total Nameplate Capacity of Equipment Operated Containing Insulating gas j)]	(Eq. DD-3)
Where:
User Emissionsi	=	Emissions of fluorinated GHG i from the facility (pounds).
GHGi,w	=	The weight fraction of fluorinated GHG i in insulating gas j if insulating gas j is a gas mixture, expressed as a decimal fraction. If fluorinated GHG i is not part of a gas mixture, use a value of 1.0.
Decrease in Insulating gas j Inventory	=	(pounds of insulating gas j stored in containers, but not in energized equipment, at the beginning of the year) − (pounds of insulating gas j stored in containers, but not in energized equipment, at the end of the year).
Acquisitions of Insulating gas j		=	(pounds of each insulating gas j purchased from chemical producers or distributors in bulk) + (pounds of each insulating gas j purchased from equipment manufacturers or distributors with or inside equipment, including hermetically sealed-pressure switchgear) + (pounds of each insulating gas j returned to facility after off-site recycling).
Disbursements of Insulating gas j 	=	(pounds of each insulating gas j in bulk and contained in equipment that is sold to other entities) + (pounds of each insulating gas j returned to suppliers) + (pounds of each insulating gas j sent off site for recycling) + (pounds of each insulating gas j sent off-site for destruction).
Net Increase in Total Nameplate Capacity of Equipment Operated containing insulating gas j
=	(The Nameplate Capacity of new equipment containing insulating gas j in pounds, including hermetically sealed-pressure switchgear) − (Nameplate Capacity of retiring equipment containing insulating gas j in pounds, including hermetically sealed-pressure switchgear). (Note that Nameplate Capacity refers to the full and proper charge of equipment rather than to the actual charge, which may reflect leakage).
(b) Nameplate Capacity Adjustments. Users of closed-pressure electrical equipment with a voltage capacity greater than 38 kV may measure and adjust the nameplate capacity value specified by the equipment manufacturer on the nameplate attached to that equipment, or within the equipment manufacturer's official product specifications, by following the requirements in paragraphs (b)(1) through (b)(10) of this section. Users of other electrical equipment are not permitted to adjust the nameplate capacity value of the other equipment.
(1) If you elect to measure the nameplate capacity value(s) of one or more pieces of electrical equipment with a voltage capacity greater than 38 kV, you must measure the nameplate capacity values of all the electrical equipment in your facility that has a voltage capacity greater than 38 kV and that is installed or retired in that reporting year and in subsequent reporting years.
(2) You must adopt the measured nameplate capacity value for any piece of equipment for which the absolute value of the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer equals or exceeds two percent of the nameplate capacity value most recently specified by the manufacturer.
(3) You may adopt the measured nameplate capacity value for equipment for which the absolute value of the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer is less than two percent of the nameplate capacity value most recently specified by the manufacturer, but if you elect to adopt the measured nameplate capacity for that equipment, then you must adopt the measured nameplate capacity value for all of the equipment for which the difference between the measured nameplate capacity value and the nameplate capacity value most recently specified by the manufacturer is less than two percent of the nameplate capacity value most recently specified by the manufacturer. This applies in the reporting year in which you first adopt the measured nameplate capacity for the equipment and in subsequent reporting years.
(4) Users of electrical equipment measuring the nameplate capacity of any new electrical equipment must:
(i) Record the amount of insulating gas in the equipment at the time the equipment was acquired (pounds), either per information provided by the manufacturer, or by transferring insulating gas from the equipment to a gas container and measuring the amount of insulating gas transferred. The equipment user is responsible for ensuring the gas is accounted for consistent with the methodologies specified in paragraphs (b)(4)(ii) through (b)(5) of this section. If no insulating gas was in the device when it was acquired, record this value as zero.
(ii) If insulating gas is added to the equipment subsequent to the acquisition of the equipment to energize it the first time, transfer the insulating gas to the equipment to reach the temperature-compensated design operating pressure per manufacturer specifications and measure and calculate the total amount of covered insulating gas added to the device using one of the methods specified in paragraphs (b)(4)(ii)(A) and (B) of this section.
(A) To determine the amount of covered insulating gas transferred to the electrical equipment, weigh the gas container being used to fill the device prior to, and after, the addition of the covered insulating gas to the electrical equipment, and subtract the second value (after-transfer gas container weight) from the first value (prior-to-transfer gas container weight). Account for any gas contained in hoses before and after the transfer.
(B) Connect a mass flow meter between the electrical equipment and a gas cart. Transfer gas to the equipment to reach the temperature-compensated design operating pressure per manufacturer specifications. Close the connection to the GIE from the mass flow meter hose and ensure that the gas trapped in the filling hose returns through the mass flow meter. Calculate the amount of gas transferred from the mass reading on the mass flow meter.
(iii) Sum the results of paragraphs (b)(4)(i) and (ii) to obtain the measured nameplate capacity for the new equipment.
(5) Electrical equipment users measuring the nameplate capacity of any retiring electrical equipment must:
(i) Record the initial system pressure and vessel temperature prior to removing any insulating gas.
(ii) Convert the initial system pressure to a temperature-compensated initial system pressure by using the temperature/pressure curve for that insulating gas.
(iii) If the temperature-compensated initial system pressure of the electrical equipment does not match the temperature-compensated design operating pressure specified by the equipment manufacturer, you may either:
(A) Add or remove insulating gas to/from the electrical equipment until the manufacturer-specified value is reached, or
(B) If the temperature-compensated initial system pressure of the electrical equipment is no less than 90 percent of the temperature-compensated design operating pressure specified by the manufacturer (in absolute terms), use Equation DD-4 to calculate the nameplate capacity based on the mass recorded under paragraph (b)(5)(vi) of this section.
(iv) Follow one of the following processes, depending on the methodology being used to measure the amount of gas recovered:
(A) Connect a mass flow meter between the electrical equipment and a gas cart; or
(B) Weigh the gas container being used to receive the gas and record this value.
(v) Recover insulating gas from the electrical equipment until five minutes after the pressure in the electrical equipment reaches the blank-off pressure unless the integrity of the electrical equipment has been compromised in such a way that air will be drawn into the electrical equipment and gas cart if the electrical equipment is drawn into a vacuum. If the integrity of the electrical equipment has been so compromised, recover the insulating gas until the pressure in the electrical equipment is no higher than zero pounds per square inch gauge (0 psig).
(vi) Record the amount of insulating gas recovered (pounds), either based on the reading from the mass flow meter, or by weighing the gas container that received the gas and subtracting the weight recorded pursuant to paragraph (b)(5)(iv)(B) of this section from this value. Account for any gas contained in hoses before and after the transfer. The amount of gas recovered shall be the measured nameplate capacity for the electrical equipment unless the final temperature-compensated pressure of the electrical equipment exceeds 0.068 psia (3.5 Torr) or the electrical equipment user is calculating the nameplate capacity pursuant to paragraph (b)(5)(iii)(B) of this section, in which cases the measured nameplate capacity shall be the result of Equation DD-4.
(vii) If you are calculating the nameplate capacity pursuant to paragraph (b)(5)(iii)(B), use Equation DD-4 to do so.
	NCC=PNCPi-PfxMR	DD-4
Where:
NCC	=	Nameplate capacity of the equipment measured and calculated by the equipment user (pounds).
Pi	=	Initial temperature-compensated pressure of the equipment, based on the temperature-pressure curve for the insulating gas (psia).
Pf	=	Final temperature-compensated pressure of the equipment, based on the temperature-pressure curve for the insulating gas (psia). This may be equated to zero if the final temperature-compensated pressure of the equipment is equal to or lower than 0.068 psia (3.5 Torr).
PNC	=	Temperature-compensated pressure of the equipment at the manufacturer-specified filling density of the equipment (i.e., at the full and proper charge, psia).
MR	=	Mass of insulating gas recovered from the equipment, measured in paragraph (b)(5)(vi) of this section (pounds).
(viii) Record the final system pressure and vessel temperature.
(6) Instead of measuring the nameplate capacity of electrical equipment when it is retired, users may measure the nameplate capacity of electrical equipment during maintenance activities that require opening the gas compartment, but they must follow the procedures set forth in paragraph (b)(5) of this section.
(7) If the electrical equipment will remain energized, and the electrical equipment user is adopting the user-measured nameplate capacity, the electrical equipment user must affix a revised nameplate capacity label, showing the revised nameplate value and the year the nameplate capacity adjustment process was performed, to the device by the end of the calendar year in which the process was completed. The manufacturer's previous nameplate capacity label must remain visible after the revised nameplate capacity label is affixed to the device.
(8) For each piece of electrical equipment whose nameplate capacity was adjusted during the reporting year, the revised nameplate capacity value must be used in all provisions wherein the nameplate capacity is required to be recorded, reported, or used in a calculation in this subpart unless otherwise specified herein.
(9) The nameplate capacity of a piece of electrical equipment may only be adjusted more than once if the physical capacity of the device has changed (e.g., replacement of bushings) after the initial adjustment was performed, in which case the equipment user must adjust the nameplate capacity pursuant to the provisions of this paragraph (b).
(10) Measuring devices used to measure the nameplate capacity of electrical equipment under this paragraph (b) must meet the following accuracy and precision requirements:
(i) Flow meters must be certified by the manufacturer to be accurate to within one percent of the largest value that the flow meter can, according to the manufacturer's specifications, accurately record.
(ii) Pressure gauges must be certified by the manufacturer to be accurate within 0.5% of the largest value that the gauge can, according to the manufacturer's specifications, accurately record.
(iii) Temperature gauges must be certified by the manufacturer to be accurate within +/-1.0° F.
(iv) Scales must be certified by the manufacturer to be accurate to within one percent of the true weight.
 Amend § 98.304 by removing and reserving paragraph (a) and revising paragraphs (b)(1), (2), and (4) to read as follows:
§ 98.304 Monitoring and QA/QC requirements.
*	*	*	*	*
(b) *	*	*
(1) Review inputs to Equation DD-3 of this section to ensure inputs and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the Decrease in fluorinated GHG Inventory and the Net Increase in Total Nameplate Capacity may be calculated as negative numbers.
*	*	*	*	*
(4) Ensure that in addition to fluorinated GHG purchased from bulk gas distributors, fluorinated GHG purchased from Original Equipment Manufacturers (OEM) and fluorinated GHG returned to the facility from off-site recycling are also accounted for among the total additions.
*	*	*	*	*
 Revise § 98.305 to read as follows:
§ 98.305 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from equipment with a similar nameplate capacity for fluorinated GHGs, and from similar equipment repair, replacement, and maintenance operations.
 Amend § 98.306 by revising paragraphs (a) introductory text, (d) through (l), and (n) introductory text, and adding paragraphs (o) through (r) to read as follows:
§ 98.306 Data reporting requirements.
*	*	*	*	*
(a) Nameplate capacity of equipment (pounds) containing each insulating gas:
*	*	*	*	*
(d) Pounds of each insulating gas stored in containers, but not in energized equipment, at the beginning of the year.
(e) Pounds of each insulating gas stored in containers, but not in energized equipment, at the end of the year.
(f) Pounds of each insulating gas purchased in bulk from chemical producers or distributors.
(g) Pounds of each insulating gas purchased from equipment manufacturers or distributors with or inside equipment, including hermetically sealed-pressure switchgear.
(h) Pounds of each insulating gas returned to facility after off-site recycling.
(i) Pounds of each insulating gas in bulk and contained in equipment sold to other entities.
(j) Pounds of each insulating gas returned to suppliers.
(k) Pounds of each insulating gas sent off-site for recycling.
(l) Pounds of each insulating gas sent off-site for destruction.
*	*	*	*	*
(n) The number of insulating gas containing pieces of equipment in each of the following equipment categories:
*	*	*	*	*
(o) The total of the nameplate capacity values most recently assigned by the electrical equipment manufacturer(s) to each of the following groups of equipment:
(1) All new equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year.
(2) All retiring equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year.
(p) The total of the nameplate capacity values measured by the electrical equipment user for each of the following groups of equipment:
(1) All new equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year.
(2) All retiring equipment whose nameplate capacity values were measured by the user under this subpart and for which the user adopted the user-measured nameplate capacity value during the year.
(q) For each unique insulating gas reported in paragraphs (a), (d) through (l), and (n) of this section, an ID number or other appropriate descriptor.
(r) For each ID number or descriptor reported in paragraph (q) of this section for each unique insulating gas, the name (as required in § 98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas in the insulating gas.
 Revise § 98.307 to read as follows:
§ 98.307 Records that must be retained.
(a) In addition to the information required by § 98.3(g), you must retain records of the information reported and listed in § 98.306.
(b) For each piece of electrical equipment whose nameplate capacity is measured by the equipment user, retain records of the following:
(1) Equipment manufacturer name.
(2) Year equipment was manufactured. If the date year the equipment was manufactured cannot be determined, report a best estimate of the year of manufacture and record how the estimated year was determined.
(3) Manufacturer serial number. For any piece of equipment whose serial number is unknown (e.g., the serial number does not exist or is not visible), another unique identifier must be recorded as the manufacturer serial number. The electrical equipment user must retain documentation that allows for each electrical equipment to be readily identifiable.
(4) Equipment type (i.e., closed-pressure vs. hermetically sealed-pressure).
(5) Equipment voltage capacity (in kilovolts).
(6) The name and GWP of each insulating gas used.
(7) Nameplate capacity value (pounds), as specified by the equipment manufacturer. The value must reflect the latest value specified by the manufacturer during the reporting year.
(8) Nameplate capacity value (pounds) measured by the equipment user.
(9) The date the nameplate capacity measurement process was completed.
(10) The measurements and calculations used to calculate the value in paragraph (b)(8) of this section.
(11) The temperature-pressure curve and/or other information used to derive the initial and final temperature-adjusted pressures of the equipment.
(12) Whether or not the nameplate capacity value in paragraph (b)(8) of this section has been adopted for the piece of electrical equipment.
 Amend § 98.308 by revising the definition of "Facility" and adding in alphabetical order definitions for "Energized," "Insulating gas," "New equipment," and "Retired equipment" to read as follows:
§ 98.308 Definitions.
*	*	*	*	*
Facility, with respect to an electric power system, means the electric power system as defined in this paragraph. An electric power system is comprised of all electric transmission and distribution equipment insulated with or containing fluorinated GHGs that is linked through electric power transmission or distribution lines and functions as an integrated unit, that is owned, serviced, or maintained by a single electric power transmission or distribution entity (or multiple entities with a common owner), and that is located between: (1) The point(s) at which electric energy is obtained from an electricity generating unit or a different electric power transmission or distribution entity that does not have a common owner, and (2) the point(s) at which any customer or another electric power transmission or distribution entity that does not have a common owner receives the electric energy. The facility also includes servicing inventory for such equipment that contains fluorinated GHGs.
*	*	*	*	*
Energized, for the purposes of this subpart, means connected through busbars or cables to an electrical power system or fully-charged, ready for service, and being prepared for connection to the electrical power system. Energized equipment does not include spare gas insulated equipment (including hermetically-sealed pressure switchgear) in storage that has been acquired by the facility, and is intended for use by the facility, but that is not being used or prepared for connection to the electrical power system.
Insulating gas, for the purposes of this subpart, means any fluorinated GHG or fluorinated GHG mixture, including but not limited to SF6 and PFCs, that is used as an insulating and/or arc-quenching gas in electrical equipment.
New equipment, for the purposes of this subpart, means any gas insulated equipment, including hermetically-sealed pressure switchgear, that is not energized at the beginning of the reporting year, but is energized at the end of the reporting year. This includes equipment that has been transferred while in use, meaning it has been added to the facility's inventory without being taken out of active service (e.g., when the equipment is sold to or acquired by the facility while remaining in place and continuing operation).
*	*	*	*	*
Retired equipment, for the purposes of this subpart, means any gas insulated equipment, including hermetically-sealed pressure switchgear, that is energized at the beginning of the reporting year, but is not energized at the end of the reporting year. This includes equipment that has been transferred while in use, meaning it has been removed from the facility's inventory without being taken out of active service (e.g., when the equipment is acquired by a new facility while remaining in place and continuing operation).

Subpart FF -- Underground Coal Mines
 Amend § 98.323 by revising parameter "MCFi" of Equation FF-3 in paragraph (b) introductory text to read as follows:
§ 98.323 Calculating GHG emissions.
*	*	*	*	*
(b) *	*	*
*	*	*	*	*
MCFi	=	Moisture correction factor for the measurement period, volumetric basis.
= 1 when Vi and Ci are measured on a dry basis or if both are measured on a wet basis.
= 1-(fH2O)i when Vi is measured on a wet basis and Ci is measured on a dry basis.
= 1/[1-(fH2O)i] when Vi is measured on a dry basis and Ci is measured on a wet basis.
*	*	*	*	*
 Amend § 98.326 by revising paragraph (t) to read as follows:
§ 98.326 Data reporting requirements.
*	*	*	*	*
(t) Mine Safety and Health Administration (MSHA) identification number for this coal mine.

Subpart GG -- Zinc Production
 Amend § 98.333 by revising paragraph (b)(1) introductory text to read as follows:
§ 98.333 Calculating GHG emissions.
*	*	*	*	*
(b) *	*	*
(1) For each Waelz kiln or electrothermic furnace at your facility used for zinc production, you must determine the mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into each Waelz kiln and electrothermic furnace at your facility for each year and calculate annual CO2 process emissions from each affected unit at your facility using Equation GG-1 of this section. For electrothermic furnaces, carbon containing input materials include carbon electrodes and carbonaceous reducing agents. For Waelz kilns, carbon containing input materials include carbonaceous reducing agents. If you document that a specific material contributes less than 1 percent of the total carbon into the process, you do not have to include the material in your calculation using Equation R-1 of § 98.183.
*	*	*	*	*
 Amend § 98.336 by adding paragraph (a)(6) and revising paragraph (b)(6) to read as follows:
§ 98.336 Data reporting requirements.
*	*	*	*	*
(a) *	*	*
(6) Total amount of electric arc furnace dust annually consumed by all Waelz kilns at the facility (tons).
(b) *	*	*
(6) Total amount of electric arc furnace dust annually consumed by all Waelz kilns at the facility (tons).
*	*	*	*	*

Subpart HH -- Municipal Solid Waste Landfills
 Amend § 98.343 by revising paragraph (a)(2) to read as follows:
§ 98.343 Calculating GHG emissions.
(a) *	*	*
(2) For years when material-specific waste quantity data are available, apply Equation HH-1 of this section for each waste quantity type and sum the CH4 generation rates for all waste types to calculate the total modeled CH4 generation rate for the landfill. Use the appropriate parameter values for k, DOC, MCF, DOCF, and F shown in Table HH-1 of this subpart. The annual quantity of each type of waste disposed must be calculated as the sum of the daily quantities of waste (of that type) disposed. You may use the uncharacterized MSW parameters for a portion of your waste materials when using the material-specific modeling approach for mixed waste streams that cannot be designated to a specific material type. For years when waste composition data are not available, use the bulk waste parameter values for k and DOC in Table HH-1 to this subpart for the total quantity of waste disposed in those years.
*	*	*	*	*
 Amend § 98.346 by adding paragraphs (i)(6)(i) and (ii) to read as follows:
§ 98.346 Data reporting requirements.
*	*	*	*	*
(i) *	*	*
(6) *	*	*
(i) The percentage of total recovered CH4 that is sent to each measurement location (decimal, must total to 1 across all measurement locations at the facility).
(ii) For each measurement location, the percentage of total recovered CH4 that is sent to a flare, a landfill gas to energy project, or an unknown option if gas is sent off-site for destruction and the type of destruction technology is unknown (decimal, must total to 1 for each measurement location).
*	*	*	*	*
 Revise Table HH-1 to subpart HH of part 98 to read as follows:
Table HH-1 to Subpart HH of Part 98 -- Emissions Factors, Oxidation Factors and Methods
                                    Factor
                                 Default value
                                     Units
DOC and k values -- Bulk waste option
DOC (bulk waste)
                                     0.17
                          Weight fraction, wet basis.
k (precipitation plus recirculated leachate[a] <20 inches/year)
                                     0.055
                                   yr[−1]
k (precipitation plus recirculated leachate[a] 20-40 inches/year)
                                     0.111
                                   yr[−1]
k (precipitation plus recirculated leachate[a] >40 inches/year)
                                     0.142
                                   yr[−1]
DOC and k values -- Modified bulk MSW option
DOC (bulk MSW, excluding inerts and C&D waste)
                                     0.27
                          Weight fraction, wet basis.
DOC (inerts, e.g., glass, plastics, metal, concrete)
                                     0.00
                          Weight fraction, wet basis.
DOC (C&D waste)
                                     0.08
                          Weight fraction, wet basis.
k (bulk MSW, excluding inerts and C&D waste)
                               0.02 to 0.057[b]
                                   yr[−1]
k (inerts, e.g., glass, plastics, metal, concrete)
                                     0.00
                                   yr[−1]
k (C&D waste)
                                0.02 to 0.04[b]
                                   yr[−1]
DOC and k values -- Waste composition option
DOC (food waste)
                                     0.15
                          Weight fraction, wet basis.
DOC (garden)
                                      0.2
                          Weight fraction, wet basis.
DOC (paper)
                                      0.4
                          Weight fraction, wet basis.
DOC (wood and straw)
                                     0.43
                          Weight fraction, wet basis.
DOC (textiles)
                                     0.24
                          Weight fraction, wet basis.
DOC (diapers)
                                     0.24
                          Weight fraction, wet basis.
DOC (sewage sludge)
                                     0.05
                          Weight fraction, wet basis.
DOC (inerts, e.g., glass, plastics, metal, cement)
                                     0.00
                          Weight fraction, wet basis.
DOC (Uncharacterized MSW)
                                     0.32
                          Weight fraction, wet basis.
k (food waste)
                               0.06 to 0.185[c]
                                   yr[−1]
k (garden)
                                0.05 to 0.10[c]
                                   yr[−1]
k (paper)
                                0.04 to 0.06[c]
                                   yr[−1]
k (wood and straw)
                                0.02 to 0.03[c]
                                   yr[−1]
k (textiles)
                                0.04 to 0.06[c]
                                   yr[−1]
k (diapers)
                                0.05 to 0.10[c]
                                   yr[−1]
k (sewage sludge)
                               0.06 to 0.185[c]
                                   yr[−1]
k (inerts, e.g., glass, plastics, metal, concrete)
                                     0.00
                                   yr[−1]
k (uncharacterized MSW)
                                0.055 to 0.142
                                   yr[−1]
Other parameters -- All MSW landfills
MCF
                                      1.

DOCF
                                      0.5

F
                                      0.5

OX
                        See Table HH-4 of this subpart

DE
                                     0.99

[a]Recirculated leachate (in inches/year) is the total volume of leachate recirculated from company records or engineering estimates divided by the area of the portion of the landfill containing waste with appropriate unit conversions. Alternatively, landfills that use leachate recirculation can elect to use the k value of 0.142 rather than calculating the recirculated leachate rate.
[b]Use the lesser value when precipitation plus recirculated leachate is less than 20 inches/year. Use the greater value when precipitation plus recirculated leachate is greater than 40 inches/year. Use the average of the range of values when precipitation plus recirculated leachate is 20 to 40 inches/year (inclusive). Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than calculating the recirculated leachate rate.
[c]Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate plus recirculated leachate. Use the greater value when the potential evapotranspiration rate does not exceed the mean annual precipitation rate plus recirculated leachate. Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than assessing the potential evapotranspiration rate or recirculated leachate rate.

Subpart OO --  Suppliers of Industrial Greenhouse Gases
 Amend § 98.416 by revising paragraphs (c)(6) and (7) and (d)(4), and adding paragraph (k) to read as follows:
§ 98.416 Data reporting requirements.
*	*	*	*	*
(c) *	*	*
(6) Harmonized tariff system (HTS) code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped.
(7) Customs entry summary number and importer number for each shipment.
*	*	*	*	*
(d) *	*	*
(4) Harmonized tariff system (HTS) code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped.
*	*	*	*	*
(k) For nitrous oxide, saturated perfluorocarbons, and sulfur hexafluoride, report the end use(s) for which each GHG is transferred and the aggregated annual quantity of that GHG in metric tons that is transferred to that end use application, if known.

Subpart PP --  Suppliers of Carbon Dioxide
 Amend § 98.420 by adding paragraph (a)(4) to read as follows:
§ 98.420 Definition of the source category.
(a) *	*	*
(4) Facilities with process units, including but not limited to direct air capture (DAC), that capture a CO2 stream from ambient air for purposes of supplying CO2 for commercial applications or that capture and maintain custody of a CO2 stream in order to sequester or otherwise inject it underground.
*	*	*	*	*
 Amend § 98.422 by adding paragraph (e) to read as follows:
§ 98.422 GHGs to report.
*	*	*	*	*
(e) Mass of CO2 captured from DAC process units.
(1) Mass of CO2 captured from ambient air.
(2) Mass of CO2 captured from any on-site heat and/or electricity generation, where applicable.
 Amend § 98.423 by revising paragraphs (a)(3)(i) introductory text and (a)(3)(ii) introductory text to read as follows:
§ 98.423 Calculating CO2 supply.
(a) *	*	*
(3) *	*	*
(i) For facilities with production process units, DAC process units, or production wells that capture or extract a CO2 stream and either measure it after segregation or do not segregate the flow, calculate the total CO2 supplied in accordance with Equation PP-3a in paragraph (a)(3).
*	*	*	*	*
(ii) For facilities with production process units or DAC process units that capture a CO2 stream and measure it ahead of segregation, calculate the total CO2 supplied in accordance with Equation PP-3b.
*	*	*	*	*
 Amend § 98.426 by adding paragraph (i) to read as follows:
§ 98.426 Data reporting requirements.
*	*	*	*	*
(i) If you capture a CO2 stream at a facility with a DAC process unit, report the annual quantity of on-site and off-site electricity or heat generated for each DAC process unit as specified in paragraphs (i)(1) through (3) of this section. The quantities specified in paragraphs (i)(1) through (3) of this section must be provided per energy source if known and must represent the electricity or heat used for the DAC process unit starting with air intake and ending with the compressed CO2 stream (i.e., the CO2 stream ready for supply for commercial applications or, if maintaining custody of the stream, sequestration or injection of the stream underground).
(1) Electricity excluding combined heat and power (CHP). If electricity is provided to a dedicated meter for the DAC process unit, report the annual quantity of electricity consumed, in megawatt hours (MWh), and the information in paragraph (i)(1)(i) or (ii) of this section.
(i) If the electricity is sourced from a grid connection, report the following information:
(A) State where the facility with the DAC process unit is located.
(B) County where the facility with the DAC process unit is located.
(C) Name of the electric utility company that supplied the electricity as shown on the last monthly bill issued by the utility company during the reporting period.
(D) Name of the electric utility company that delivered the electricity. In states with regulated electric utility markets, this will generally be the same utility reported under paragraph (i)(1)(i)(C) of this section, but in states with deregulated electric utility markets, this may be a different utility company.
(E)  Annual quantity of electricity consumed in MWh, calculated as the sum of the total energy usage values specified in all billing statements received during the reporting year. Most customers will receive 12 monthly billing statements during the reporting year. Many utilities bill their customers per kilowatt-hour (kWh); usage values on bills that are based on kWh should be divided by 1,000 to report the usage in MWh as required under this paragraph.
(ii) If electricity is sourced from on-site or through a contractual mechanism for dedicated off-site generation, for each applicable energy source specified in paragraphs (i)(1)(ii)(A) through (G) of this section, report the annual quantity of electricity consumed, in MWh. If the on-site electricity source is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit.
(A) Non-hydropower renewable sources including solar, wind, geothermal and tidal.(B) Hydropower.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
(2) Heat excluding CHP. For each applicable energy source specified in paragraphs (i)(2)(i) through (vii) of this section, report the annual quantity of heat, steam, or other forms of thermal energy sourced from on-site or through a contractual mechanism for dedicated off-site generation, in megajoules (MJ).
(i) Solar.
(ii) Geothermal.
(iii) Natural gas.
(iv) Oil.
(v) Coal.
(vi) Nuclear.
(vii) Other.
(3) CHP. (i) Electricity from CHP. If electricity from CHP is sourced from on-site or through a contractual mechanism for dedicated off-site generation, for each applicable energy source specified in paragraphs (i)(3)(i)(A) through (G) of this section, report the annual quantity consumed, in MWh. If the on-site electricity source for CHP is natural gas, oil, or coal, also indicate whether flue gas is also captured by the DAC process unit.
(A) Non-hydropower renewable sources including solar, wind, geothermal and tidal.
(B) Hydropower.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
(ii) Heat from CHP.  For each applicable energy source specified in paragraphs (i)(3)(ii)(A) through (G) of this section, report the quantity of heat, steam, or other forms of thermal energy from CHP sourced from on-site or through a contractual mechanism for dedicated off-site generation, in MJ.
(A) Solar.
(B) Geothermal.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
 Amend § 98.427 by revising paragraph (a) to read as follows:
§ 98.427 Records that must be retained.
*	*	*	*	*
(a) The owner or operator of a facility containing production process units or DAC process units must retain quarterly records of captured or transferred CO2 streams and composition.
*	*	*	*	*

Subpart SS --  Electrical Equipment Manufacture or Refurbishment
 Revise § 98.450 to read as follows:
§ 98.450 Definition of the source category.
The electrical equipment manufacturing or refurbishment category consists of processes that manufacture or refurbish gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers (including gas-containing components of such equipment) containing fluorinated GHGs, including but not limited to sulfur-hexafluoride (SF6) and perfluorocarbons (PFCs). The processes include equipment testing, installation, manufacturing, decommissioning and disposal, refurbishing, and storage in gas cylinders and other containers.
 Revise § 98.451 to read as follows:
§ 98.451 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an electrical equipment manufacturing or refurbishing process and the facility meets the requirements of § 98.2(a)(2). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO2e per year emission threshold in § 98.2(a)(2), follow the requirements of § 98.2(b), with one exception. Instead of following the requirement of § 98.453 to calculate emissions from electrical equipment manufacture or refurbishment, you must calculate emissions of each fluorinated GHG, including but not limited to SF6 and PFCs, and then sum the emissions of each fluorinated GHG resulting from manufacturing and refurbishing electrical equipment using equation SS-1 of this subpart.
	E=jiPj*GHGi,w* GWPi* EF*0.000453592 	(Eq. SS-1)
Where:
E	=	Annual production process emissions for threshold applicability purposes (metric tons CO2e).
Pj	=	Total annual purchases of insulating gas j (lbs).
GHGi,w	=	The weight fraction of fluorinated GHG i in insulating gas j if insulating gas j is a gas mixture. If not a mixture, use 1.
GWPi	=	Gas-appropriate GWP as provided in Table A-1 to subpart A of this part.
EF	=	Emission factor for electrical transmission and distribution equipment (lbs emitted/lbs purchased). For all gases, use an emission factor of 0.1.
i	=	fluorinated GHG contained in the electrical transmission and distribution equipment.
0.000453592	=	conversion factor from lbs to metric tons.
 Amend § 98.452 by revising paragraph (a) to read as follows:
§ 98.452 GHGs to report.
(a) You must report emissions of each fluorinated GHG, including but not limited to SF6 and PFCs, at the facility level. Annual emissions from the facility must include fluorinated GHG emissions from equipment that is installed at an off-site electric power transmission or distribution location whenever emissions from installation activities (e.g., filling) occur before the title to the equipment is transferred to the electric power transmission or distribution entity.
*	*	*	*	*
 Amend § 98.453 by:
a. Revising paragraph (a);
b. Removing and reserving paragraph (b);
c. Revising paragraphs (c) through (g), (h) introductory text, and (i).
The revisions read as follows:
§ 98.453 Calculating GHG emissions.
(a) For each electrical equipment manufacturer or refurbisher, estimate the annual emissions of each fluorinated GHG using the mass-balance approach in Equation SS-2 of this section:
User emissionsi = GHGi,w * [(Decrease in insulating gas j Inventory) + (Acquisitions of insulating gas j)  -  (Disbursements of insulating gas j)] 	(Eq. SS-2)

Where:
User emissionsi		=	Annual emissions of each fluorinated GHG i (pounds).
GHGi,w			=	The weight fraction of fluorinated GHG i in insulating gas j if insulating gas j is a gas mixture, expressed as a decimal fraction. If fluorinated GHG i is not part of a gas mixture, use a value of 1.0.
Decrease in insulating gas j Inventory=	(Pounds of insulating gas j stored in containers at the beginning of the year) − (Pounds of insulating gas j stored in containers at the end of the year).
Acquisitions of insulating gas j	 =	(Pounds of each insulating gas j purchased from chemical producers or suppliers in bulk) + (Pounds of each insulating gas j returned by equipment users) + (Pounds of each insulating gas j returned to site after off-site recycling).
Disbursements of insulating gas j	=	(Pounds of each insulating gas j contained in new equipment delivered to customers) + (Pounds of each insulating gas j delivered to equipment users in containers) + (Pounds of each insulating gas j returned to suppliers) + (Pounds of each insulating gas j sent off site for recycling) + (Pounds of each insulating gas j sent off-site for destruction).
(b) [Reserved]
(c) Estimate the disbursements of each insulating gas j (including, but not limited to SF6 and PFCs) sent to customers in new equipment or cylinders or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers using Equation SS-3 of this section:
	DGHG= p=1nQp	   (Eq.SS-3)
Where:
DGHG	=	The annual disbursement of each insulating gas j sent to customers in new equipment or cylinders or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers.
Qp	=	The mass of each insulating gas j charged into equipment or containers over the period p sent to customers or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers.
n	=	The number of periods in the year.
(d) Estimate the mass of each insulating gas j (including, but not limited to SF6 and PFCs) disbursed to customers in new equipment or cylinders over the period p by monitoring the mass flow of each insulating gas j into the new equipment or cylinders using a flowmeter, or by weighing containers before and after gas from containers is used to fill equipment or cylinders, or by using the nameplate capacity of the equipment.
(e) If the mass of insulating gas j disbursed to customers in new equipment or cylinders over the period p is estimated by weighing containers before and after gas from containers is used to fill equipment or cylinders, estimate this quantity using Equation SS-4 of this section:
	Qp= MB- ME-EL 	(Eq.SS-4)
Where:
Qp	=	The mass of each insulating gas j charged into equipment or containers over the period p sent to customers or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers.
MB	=	The mass of the contents of the containers used to fill equipment or cylinders at the beginning of period p.
ME	=	The mass of the contents of the containers used to fill equipment or cylinders at the end of period p.
EL	=	The mass of each insulating gas j emitted during the period p downstream of the containers used to fill equipment or cylinders and in cases where a flowmeter is used, downstream of the flowmeter during the period p (e.g., emissions from hoses or other flow lines that connect the container to the equipment or cylinder that is being filled).
(f) If the mass of each insulating gas j (including, but not limited to SF6 and PFCs) disbursed to customers in new equipment or cylinders over the period p is determined using a flowmeter, estimate this quantity using Equation SS-5 of this section:
	Qp= Mmr- EL 	(Eq. SS-5)
Where:
Qp	=	The mass of each insulating gas j (including, but not limited to SF6 and PFCs) charged into equipment or containers over the period p sent to customers or sent off-site for other purposes including for recycling, for destruction or to be returned to suppliers.
Mmr	=	The mass of each insulating gas j that has flowed through the flowmeter during the period p.
EL	=	The mass of each insulating gas j emitted during the period p downstream of the containers used to fill equipment or cylinders and in cases where a flowmeter is used, downstream of the flowmeter during the period p (e.g., emissions from hoses or other flow lines that connect the container to the equipment that is being filled).
(g) Estimate the mass of each insulating gas j emitted during the period p downstream of the containers used to fill equipment or cylinders (e.g., emissions from hoses or other flow lines that connect the container to the equipment or cylinder that is being filled) using Equation SS-6 of this section:
	EL=j=0nFCi*EFCi 	(Eq. SS-6)
Where:
EL	=	The mass of each fluorinated GHG (including, but not limited to SF6 and PFCs) or fluorinated GHG mixture emitted during the period p downstream of the containers used to fill equipment or cylinders and in cases where a flowmeter is used, downstream of the flowmeter during the period p (e.g., emissions from hoses or other flow lines that connect the container to the equipment or cylinder that is being filled).
FCi	=	The total number of fill operations over the period p for the valve-hose combination Ci.
EFCi	=	The emission factor for the valve-hose combination Ci.
n	=	The number of different valve-hose combinations C used during the period p.

(h) If the mass of each insulating gas j disbursed to customers in new equipment or cylinders over the period p is determined by using the nameplate capacity, or by using the nameplate capacity of the equipment and calculating the partial shipping charge, use the methods in either paragraph (h)(1) or (h)(2) of this section.
*	*	*	*	*
(i) Estimate the annual emissions of each insulating gas j from the equipment that is installed at an off-site electric power transmission or distribution location before the title to the equipment is transferred by using Equation SS-7 of this section:
	EI=GHGi, w*MF+MC-NI 	Eq. SS-7
Where:
EI	=	Total annual emissions of each insulating gas j from equipment installation at electric transmission or distribution facilities.
GHGi,w 	= 	The weight fraction of fluorinated GHG i in insulating gas j if insulating gas j is a gas mixture, expressed as a decimal fraction. If the GHG i is not part of a gas mixture, use a value of 1.0.
MF	=	The total annual mass of each insulating gas j, in pounds, used to fill equipment during equipment installation at electric transmission or distribution facilities.
MC	=	The total annual mass of each insulating gas j, in pounds, used to charge the equipment prior to leaving the electrical equipment manufacturer facility.
NI	=	The total annual nameplate capacity of the equipment, in pounds, installed at electric transmission or distribution facilities.
 Amend § 98.454 by removing and reserving paragraph (a) and revising paragraphs (b), (d) through (f), and (h)(1) through (4) to read as follows:
§ 98.454 Monitoring and QA/QC requirements.
*	*	*	*	*
(b) Ensure that all the quantities required by the equations of this subpart have been measured using either flowmeters with an accuracy and precision of +-1 percent of full scale or better or scales with an accuracy and precision of +-1 percent of the filled weight (gas plus tare) of the containers of each insulating gas that are typically weighed on the scale. For scales that are generally used to weigh cylinders containing 115 pounds of gas when full, this equates to +-1 percent of the sum of 115 pounds and approximately 120 pounds tare, or slightly more than +-2 pounds. Account for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier (e.g., for the contents of cylinders containing new gas or for the heels remaining in cylinders returned to the gas supplier) if the supplier provides documentation verifying that accuracy standards are met; however, you remain responsible for the accuracy of these masses and weights under this subpart.
*	*	*	*	*
(d) For purposes of Equations SS-6 of this subpart, the emission factor for the valve-hose combination (EFC) must be estimated using measurements and/or engineering assessments or calculations based on chemical engineering principles or physical or chemical laws or properties. Such assessments or calculations may be based on, as applicable, the internal volume of hose or line that is open to the atmosphere during coupling and decoupling activities, the internal pressure of the hose or line, the time the hose or line is open to the atmosphere during coupling and decoupling activities, the frequency with which the hose or line is purged and the flow rate during purges. You must develop a value for EFc (or use an industry-developed value) for each combination of hose and valve fitting, to use in Equation SS-6 of this subpart. The value for EFC must be determined for each combination of hose and valve fitting of a given diameter or size. The calculation must be recalculated annually to account for changes to the specifications of the valves or hoses that may occur throughout the year.
(e) Electrical equipment manufacturers and refurbishers must account for emissions of each insulating gas that occur as a result of unexpected events or accidental losses, such as a malfunctioning hose or leak in the flow line, during the filling of equipment or containers for disbursement by including these losses in the estimated mass of each insulating gas emitted downstream of the container or flowmeter during the period p.
(f) If the mass of each insulating gas j disbursed to customers in new equipment over the period p is determined by assuming that it is equal to the equipment's nameplate capacity or, in cases where equipment is shipped with a partial charge, equal to its partial shipping charge, equipment samples for conducting the nameplate capacity tests must be selected using the following stratified sampling strategy in this paragraph. For each make and model, group the measurement conditions to reflect predictable variability in the facility's filling practices and conditions (e.g., temperatures at which equipment is filled). Then, independently select equipment samples at random from each make and model under each group of conditions. To account for variability, a certain number of these measurements must be performed to develop a robust and representative average nameplate capacity (or shipping charge) for each make, model, and group of conditions. A Student T distribution calculation should be conducted to determine how many samples are needed for each make, model, and group of conditions as a function of the relative standard deviation of the sample measurements. To determine a sufficiently precise estimate of the nameplate capacity, the number of measurements required must be calculated to achieve a precision of one percent of the true mean, using a 95 percent confidence interval. To estimate the nameplate capacity for a given make and model, you must use the lowest mean value among the different groups of conditions, or provide justification for the use of a different mean value for the group of conditions that represents the typical practices and conditions for that make and model. Measurements can be conducted using SF6, another gas, or a liquid. Re-measurement of nameplate capacities should be conducted every five years to reflect cumulative changes in manufacturing methods and conditions over time.
*	*	*	*	*
(h) *	*	*
(1) Review inputs to Equation SS-2 of this subpart to ensure inputs and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the decrease in the inventory for each insulating gas may be calculated as negative.
(3) Ensure that for each insulating gas, the beginning-of-year inventory matches the end-of-year inventory from the previous year.
(4) Ensure that for each insulating gas, in addition to the insulating gas purchased from bulk gas distributors, the insulating gas returned from equipment users with or inside equipment and the insulating gas returned from off-site recycling are also accounted for among the total additions.
 Amend § 98.456 by revising paragraphs (a) through (k) and (n) through (s), and adding paragraphs (u) and (v) to read as follows:
§ 98.456 Data reporting requirements.
*	*	*	*	*
(a) Pounds of each insulating gas stored in containers at the beginning of the year.
(b) Pounds of each insulating gas stored in containers at the end of the year.
(c) Pounds of each insulating gas purchased in bulk.
(d) Pounds of each insulating gas returned by equipment users with or inside equipment.
(e) Pounds of each insulating gas returned to site from off site after recycling.
(f) Pounds of each insulating gas inside new equipment delivered to customers.
(g) Pounds of each insulating gas delivered to equipment users in containers.
(h) Pounds of each insulating gas returned to suppliers.
(i) Pounds of each insulating gas sent off site for destruction.
(j) Pounds of each insulating gas sent off site to be recycled.
(k) The nameplate capacity of the equipment, in pounds, delivered to customers with insulating gas inside, if different from the quantity in paragraph (f) of this section.
*	*	*	*	*
(n) The total number of fill operations for each hose and valve combination, or, FCi of Equation SS-6 of this subpart.
(o) If the mass of each insulating gas disbursed to customers in new equipment over the period p is determined according to the methods required in § 98.453(h), report the mean value of nameplate capacity in pounds for each make, model, and group of conditions.
(p) If the mass of each insulating gas disbursed to customers in new equipment over the period p is determined according to the methods required in § 98.453(h), report the number of samples and the upper and lower bounds on the 95-percent confidence interval for each make, model, and group of conditions.
(q) Pounds of each insulating gas used to fill equipment at off-site electric power transmission or distribution locations, or MF, of Equation SS-7 of this subpart.
(r) Pounds of each insulating gas used to charge the equipment prior to leaving the electrical equipment manufacturer or refurbishment facility, or MC, of Equation SS-7 of this subpart.
(s) The nameplate capacity of the equipment, in pounds, installed at off-site electric power transmission or distribution locations used to determine emissions from installation, or NI, of Equation SS-7 of this subpart.
*	*	*	*	*
(u) For each unique insulating gas reported in paragraphs (a) through (j) and (o) through (r) of this section, an ID number or other appropriate descriptor.
(v) For each ID number or descriptor reported in paragraph (u) of this section for each unique insulating gas, the name (as required in § 98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas in the insulating gas.
 Revise § 98.458 to read as follows:
§ 98.458 Definitions.
Except as specified in this section, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
Insulating gas, for the purposes of this subpart, means any fluorinated GHG or fluorinated GHG mixture, including but not limited to SF6 and PFCs, that is used as an insulating and/or arc-quenching gas in electrical equipment.
Subpart UU -- Injection of Carbon Dioxide
 Amend § 98.470 by redesignating paragraph (c) as paragraph (d) and adding new paragraph (c) to read as follows:
§ 98.470 Definition of the source category.
*	*	*	*	*
(c) If you report under subpart VV of this part for a well or group of wells, you are not required to report under this subpart for that well or group of wells.
 Add subpart VV to read as follows:
Subpart VV -- Geologic Sequestration of Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916
§ 98.480 Definition of the source category.
(a) This source category pertains to carbon dioxide (CO2) that is injected in enhanced recovery operations for oil and other hydrocarbons (CO2-EOR) in which all of the following apply:
(1) You are using the International Standards Organization (ISO) standard designated as CSA/ANSI ISO 27916:2019, "Carbon Dioxide Capture, Transportation and Geological Storage  -- Carbon Dioxide Storage Using Enhanced Oil Recovery (CO2-EOR)" (CSA/ANSI ISO 27916:2019) (incorporated by reference, see §98.7) as a method of quantifying geologic sequestration of CO2 in association with EOR operations.
(2) You are not reporting under subpart UU of this part.
(3) You are not reporting under subpart RR of this part.
(b) This source category does not include wells permitted as Class VI under the Underground Injection Control program.
(c) If you are subject to only this subpart, you are not required to report emissions under subpart C of this part or any other subpart listed in §98.2(a)(1) or (a)(2).
§ 98.481 Reporting threshold.
(a) You must report under this subpart if your CO2-EOR project uses CSA/ANSI ISO 27916:2019 (incorporated by reference, see §98.7) as a method of quantifying geologic sequestration of CO2 in association with CO2-EOR operations. There is no threshold for reporting.
(b) The requirements of §98.2(i) do not apply to this subpart. Once a CO2-EOR project becomes subject to the requirements of this subpart, you must continue for each year thereafter to comply with all requirements of this subpart, including the requirement to submit annual reports until the facility has met the requirements of paragraphs (b)(1) and (b)(2) of this section and submitted a notification to discontinue reporting according to paragraph (b)(3) of this section.
(1) Discontinuation of reporting under this subpart must follow the requirements set forth under Clause 10 of CSA/ANSI ISO 27916:2019.
(2) CO2-EOR project termination is completed when all of the following occur:
(A) Cessation of CO2 injection.
(B) Cessation of hydrocarbon production from the project reservoir; and
(C) Wells are plugged and abandoned unless otherwise required by the appropriate regulatory authority.
(3) You must notify the Administrator of your intent to cease reporting and provide a copy of the CO2-EOR project termination documentation.
§ 98.482 GHGs to report.
You must report the following from Clause 8 of CSA/ANSI ISO 27916:2019 (incorporated by reference, see §98.7):
(a) The mass of CO2 received by the CO2-EOR project.
(b) The mass of CO2 loss from the CO2-EOR project operations.
(c) The mass of native CO2 produced and captured.
(d) The mass of CO2 produced and sent off-site.
(e) The mass of CO2 loss from the EOR complex.
(f) The mass of CO2 stored in association with CO2-EOR.
§ 98.483 Calculating CO2 geologic sequestration
You must calculate CO2 sequestered using the following quantification principles from Clause 8.2 of CSA/ANSI ISO 27916:2019 (incorporated by reference, see §98.7).
(a) You must calculate the mass of CO2 stored in association with CO2-EOR (mstored) in the reporting year by subtracting the mass of CO2 loss from operations and the mass of CO2 loss from the EOR complex from the total mass of CO2 input (as specified in Equation VV-1 of this section).
	(Equation VV-1)
Where:
mstored	=	the annual quantity of associated storage in metric tons of CO2 mass.
minput	=	the total mass of CO2 mreceived by the EOR project plus mnative (see Clause 8.3 and paragraph (c) of this section), metric tons. Native CO2 produced and captured in the CO2-EOR project (mnative) can be quantified and included in minput.
mloss operations	=	the total mass of CO2 loss from project operations (see Clauses 8.4.1 through 8.4.5 and paragraph (d) of this section), metric tons.
mloss EOR complex	=	the total mass of CO2 loss from the EOR complex (see Clause 8.4.6), metric tons.

(b) The manner by which associated storage is quantified must assure completeness and preclude double counting. The annual mass of CO2 that is recycled and reinjected into the EOR complex must not be quantified as associated storage. Loss from the CO2 recycling facilities must be quantified.
(c) You must quantify the total mass of CO2 input (minput) in the reporting year according to paragraphs (g)(1) through (3) of this section.
(1) You must include the total mass of CO2 received at the custody transfer meter by the CO2-EOR project (mreceived).
(2) The CO2 stream received (including CO2 transferred from another CO2-EOR project) must be metered.
(A) The native CO2 recovered and included as mnative must be documented.
(B) CO2 delivered to multiple CO2-EOR projects must be allocated among those CO2-EOR projects.
(3) The sum of the quantities of allocated CO2 must not exceed the total quantities of CO2 received.
(d) You must calculate the total mass of CO2 from project operations (mloss operations) in the reporting year as specified in Equation VV-2 of this section.
		(Equation VV-2)
Where:
mloss leakage facilities	=	Loss of CO2 due to leakage from production, handling, and recycling CO2-EOR facilities (infrastructure including wellheads), metric tons.
mloss vent/flare	=	Loss of CO2 from venting/flaring from production operations, metric tons.
mloss entrained	=	Loss of CO2 due to entrainment within produced gas/oil/water when this CO2 is not separated and reinjected, metric tons.
mloss transfer	=	Loss of CO2 due to any transfer of CO2 outside the CO2-EOR project, metric tons. You must quantify any CO2 that is subsequently produced from the EOR complex and transferred offsite.
§ 98.484 Monitoring and QA/QC requirements.
You must use the applicable monitoring and quality assurance requirements set forth in Clause 6.2 of CSA/ANSI ISO 27916:2019 (incorporated by reference, see §98.7).
§ 98.485 Procedures for estimating missing data.
Whenever the value of a parameter is unavailable or the quality assurance procedures set forth in §98.484 cannot be followed, you must follow the procedures set forth in Clause 9.2 of CSA/ANSI ISO 27916:2019 (incorporated by reference, see §98.7).
§ 98.486 Data reporting requirements.
In addition to the information required by §98.3(c), the annual report shall contain the following information, as applicable:
(a) The annual quantity of associated storage in metric tons of CO2 (mstored).
(b) The density of CO2 if volumetric units are converted to mass in order to be reported for annual quantity of CO2 stored.
(c) The annual quantity of CO2 input (minput) and the information in paragraphs (c)(1) and (2) of this section.
(1) The annual total mass of CO2 received at the custody transfer meter by the CO2-EOR project, including CO2 transferred from another CO2-EOR project (mreceived).
(2) The annual mass of native CO2 produced and captured in the CO2-EOR project (mnative).
(d) The annual mass of CO2 that is recycled and reinjected into the EOR complex.
(e) The annual total mass of CO2 loss from project operations (mloss operations), and the information in paragraphs (e)(1) through (4) of this section.
(1) Loss of CO2 due to leakage from production, handling, and recycling CO2-EOR facilities (infrastructure including wellheads) (mloss leakage facilities).
(2) Loss of CO2 from venting/flaring from production operations (mloss vent/flare).
(3) Loss of CO2 due to entrainment within produced gas/oil/water when this CO2 is not separated and reinjected (mloss entrained).
(4) Loss of CO2 due to any transfer of CO2 outside the CO2-EOR project (mloss transfer).
(f) The total mass of CO2 loss from the EOR complex (mloss EOR complex).
(g) Annual documentation that contains the following components as described in Clause 4.4 of CSA/ANSI ISO 27916:2019 (incorporated by reference, see §98.7):
(1) The formulas used to quantify the annual mass of associated storage, including the mass of CO2 delivered to the CO2-EOR project and losses during the period covered by the documentation (see Clause 8 and Annex B).
(2) The methods used to estimate missing data and the amounts estimated as described in Clause 9.2.
(3) The approach and method for quantification utilized by the operator, including accuracy, precision, and uncertainties (see Clause 8 and Annex B).
(4) A statement describing the nature of validation or verification including the date of review, process, findings, and responsible person or entity.
(5) Source of each CO2 stream quantified as associated storage (see Clause 8.3).
(6) A description of the procedures used to detect and characterize the total CO2 leakage from the EOR complex.
(7) If only the mass of anthropogenic CO2 is considered for mstored, a description of the derivation and application of anthropogenic CO2 allocation ratios for all the terms described in Clauses 8.1 to 8.4.6.
(8) Any documentation provided by a qualified independent engineer or geologist, who certifies that the documentation provided, including the mass balance calculations as well as information regarding monitoring and containment assurance, is accurate and complete.
§ 98.487 Records that must be retained.
You must follow the record retention requirements specified by §98.3(g). In addition to the records required by §98.3(g), you must comply with the record retention requirements in Clause 9.1 of CSA/ANSI ISO 27916:2019 (incorporated by reference, see §98.7).
§ 98.488 EOR Operations Management Plan
(a) You must prepare and update, as necessary, a general EOR operations management plan that provides a description of the EOR complex and engineered system (see Clause 4.3 (a)), establishes that the EOR complex is adequate to provide safe, long-term containment of CO2, and includes site-specific and other information including:
(1) Geologic characterization of the EOR complex.
(2) A description of the facilities within the CO2-EOR project.
(3) A description of all wells and other engineered features in the CO2-EOR project.
(4) The operations history of the project reservoir.
(5) The information set forth in Clauses 5 and 6 of CSA/ANSI ISO 27916:2019 (incorporated by reference, see §98.7).
(b) You must prepare initial documentation at the beginning of the quantification period, and include the following as described in the EOR Operations Management Plan:
(1) A description of the EOR complex and engineered systems (see Clause 5).
(2) The initial containment assurance (see Clause 6.1.2).
(3) The monitoring program (see Clause 6.2).
(4) The quantification method to be used (see Clause 8 and Annex B).
(5) The total mass of previously injected CO2 (if any) within the EOR complex at the beginning of the CO2-EOR project (see Clause 8.5 and Annex B).
(c) The EOR operation management plan in paragraph (a) of this section and initial documentation in paragraph (b) of this section must be submitted to the Administrator with the annual report covering the first reporting year that the facility reports under this subpart. In addition, any documentation provided by a qualified independent engineer or geologist, who certifies that the documentation provided is accurate and complete, must also be provided to the Administrator.
(d) If the EOR operations management plan is updated, the updated EOR management plan must be submitted to the Administrator with the annual report covering the first reporting year for which the updated EOR operation management plan is applicable.
§ 98.489 Definitions
Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Additional terms and definitions are provided in Clause 3 of CSA/ANSI ISO 27916:2019 (incorporated by reference, see §98.7) and incorporated herein by reference.
All references in this subpart preceded by the word Clause refer to the Clauses in CSA/ANSI ISO 27916:2019.