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Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids

§ 98.400 Definition of the source category.

This supplier category consists of natural gas liquids fractionators and local natural gas 

distribution companies.

(a) Natural gas liquids fractionators are installations that fractionate natural gas liquids 

(NGLs) into their constituent liquid products or mixtures of products (ethane, propane, normal 

butane, isobutane or pentanes plus) for supply to downstream facilities.

(b) Local Distribution Companies (LDCs) are companies that own or operate distribution 

pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end 

users and that are within a single state that are regulated as separate operating companies by

State public utility commissions or that operate as independent municipally-owned distribution 

systems. LDCs do not include pipelines (both interstate and intrastate) delivering natural gas 

directly to major industrial users and farm taps upstream of the local distribution company inlet.

(c) This supply category does not consist of the following facilities:

(1) Field gathering and boosting stations.

(2) Natural gas processing plants that separate NGLs from natural gas and produce bulk 

or y-grade NGLs but do not fractionate these NGLs into their constituent products.

(3) Facilities that meet the definition of refineries and report under subpart MM of this 

part.

(4) Facilities that meet the definition of petrochemical plants and report under subpart X 

of this part.

§ 98.401 Reporting threshold.
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Any supplier of natural gas and natural gas liquids that meets the requirements of § 

98.2(a)(4) must report GHG emissions associated with the products they supply.

§ 98.402 GHGs to report.

(a) NGL fractionators must report the CO2 emissions that would result from the complete 

combustion or oxidation of the annual quantity of ethane, propane, normal butane, isobutane, and 

pentanes plus that is produced and sold or delivered to others.

(b) LDCs must report the CO2 emissions that would result from the complete combustion 

or oxidation of the annual volumes of natural gas provided to end-users on their distribution 

systems.

§ 98.403 Calculating GHG emissions.

(a) LDCs and fractionators shall, for each individual product reported under this part, 

calculate the estimated CO2 emissions that would result from the complete combustion or 

oxidation of the products supplied using either of Calculation Methodology 1 or 2 of this 

subpart:

(1) Calculation Methodology 1. NGL fractionators shall estimate CO2 emissions that 

would result from the complete combustion or oxidation of the product(s) supplied using 

Equation NN-1 of this section. The annual volume of each NGL product supplied (Fuelh) shall 

include any amount of that NGL supplied in a mixture or blend of two or more products listed in 

Tables NN-1 and NN-2 of this subpart. The annual volume of each NGL product supplied shall 

exclude any amount of that NGL contained in bulk NGLs exiting the facility not fractionated by

the reporter (e.g., y-grade, o-grade, and other bulk NGLs). LDCs shall estimate CO2 emissions 

that would result from the complete combustion or oxidation of the natural gas received at the 

city gate (including natural gas that is transported by, but not owned by, the reporter) using 
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Equation NN-1 of this section. For each product, use the default value for higher heating value 

and CO2 emission factor in Table NN-1 of this subpart. Alternatively, for each product, a 

reporter-specific higher heating value and CO2 emission factor may be used, in place of one or 

both defaults provided they are developed using methods outlined in § 98.404. For each product, 

you must use the same volume unit throughout the equation.

Where:

CO2i = Annual CO2 mass emissions that would result from the combustion or 

oxidation of each product “h” for redelivery to all recipients (metric tons).

Fuelh = Total annual volume of product “h” supplied (volume per year, in thousand 

standard cubic feet (Mscf) for natural gas and bbl for NGLs).

HHVh = Higher heating value of product “h” supplied (MMBtu/Mscf or MMBtu/bbl).

EFh = CO2 emission factor of product “h” (kg CO2/MMBtu).

1×10−3= Conversion factor from kilograms to metric tons (MT/kg).

(2) Calculation Methodology 2. NGL fractionators shall estimate CO2 emissions that 

would result from the complete combustion or oxidation of the product(s) supplied using 

Equation NN-2 of this section. The annual volume of each NGL product supplied (Fuelh) shall 

include any amount of that NGL supplied in a mixture or blend of two or more products listed in 

Tables NN-1 and NN-2 of this subpart. The annual volume of each NGL product supplied shall 

exclude any amount of that NGL contained in bulk NGLs exiting the facility not fractionated by

the reporter (e.g., y-grade, o-grade, and other bulk NGLs). LDCs shall estimate CO2 emissions 

that would result from the complete combustion or oxidation of the natural gas received at the 

city gate (including natural gas that is transported by, but not owned by, the reporter) using 

Equation NN-2 of this section. For each product, use the default CO2 emission factor found in 

Table NN-2 of this subpart. Alternatively, for each product, a reporter-specific CO2 emission 
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factor may be used in place of the default factor, provided it is developed using methods outlined 

in § 98.404. For each product, you must use the same volume unit throughout the equation.

Where:

CO2i = Annual CO2 mass emissions that would result from the combustion or 

oxidation of each product “h” (metric tons)

Fuelh = Total annual volume of product “h” supplied (volume per year, in Mscf for 

natural gas and bbl for NGLs).

EFh = CO2 emission factor of product “h” (MT CO2/bbl, or MT CO2/Mscf)

(b) Each LDC shall follow the procedures below.

(1) For natural gas that is received for redelivery to downstream gas transmission 

pipelines and other local distribution companies, use Equation NN-3 of this section and the 

default values for the CO2 emission factors found in Table NN-2 of this subpart. Alternatively, 

reporter-specific CO2 emission factors may be used, provided they are developed using methods 

outlined in § 98.404.

Where:

CO2j = Annual CO2 mass emissions that would result from the combustion or 

oxidation of natural gas for redelivery to transmission pipelines or other 

LDCs (metric tons).

Fuel = Total annual volume of natural gas supplied to downstream gas transmission 

pipelines and other local distribution companies (Mscf per year).

EF = Fuel-specific CO2 emission factor (MT CO2/Mscf).

(2)(i) For natural gas delivered to large end-users, use Equation NN-4 of this section and 

the default values for the CO2 emission factors found in Table NN-2 of this subpart. A large enduser means any end-user facility receiving greater than or equal to 460,000 Mscf of natural gas 
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per year. If the LDC does not know the total quantity of gas delivered to the end-user facility 

based on readily available information in the LDCs possession, then large end-user means any

single meter at an end-user facility to which the LDC delivers equal to or greater than 460,000 

Mscf per year.

(ii) Alternatively, reporter-specific CO2 emission factors may be used, provided they are 

developed using methods outlined in § 98.404.

Where:

CO2k = Annual CO2 mass emissions that would result from the combustion or 

oxidation of natural gas delivered to each large end-user k, as defined in 

paragraph (b)(2)(i) of this section (metric tons).

Fuel = Total annual volume of natural gas supplied to each large end-user k, as 

defined in paragraph (b)(2)(i) of this section (Mscf per year).

EF = Fuel-specific CO2 emission factor (MT CO2/Mscf).

(3) For the net change in natural gas stored on system by the LDC during the reporting 

year, use Equation NN-5a of this section. For natural gas that is received by means other than 

through the city gate, and is not otherwise accounted for by Equation NN-1 or NN-2 of this 

section, use Equation NN-5b of this section.

(i) For natural gas received by the LDC that is injected into on-system storage, and/or 

liquefied and stored, and for gas removed from storage and used for deliveries, use Equation 

NN-5a of this section and the default value for the CO2 emission factors found in Table NN-2 of 

this subpart. Alternatively, a reporter-specific CO2 emission factor may be used, provided it is 

developed using methods outlined in § 98.404.

Where:
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CO2l = Annual CO2 mass emissions that would result from the combustion or 

oxidation of the net change in natural gas stored on system by the LDC 

within the reporting year (metric tons).

Fuel1 = Total annual volume of natural gas added to storage on-system or liquefied 

and stored in the reporting year (Mscf per year).

Fuel2 = Total annual volume of natural gas that is removed from storage or vaporized 

and removed from storage and used for deliveries to customers or other 

LDCs by the LDC within the reporting year (Mscf per year).

EF = CO2 emission factor for natural gas placed into/removed from storage (MT 

CO2/Mscf).

(ii) For natural gas received by the LDC that bypassed the city gate, use Equation NN-5b 

of this section. This includes natural gas received directly by LDC systems from producers or 

natural gas processing plants from local production, received as a liquid and vaporized for 

delivery, or received from any other source that bypassed the city gate. Use the default value for 

the CO2 emission factors found in Table NN-2 of this subpart. Alternatively, a reporter-specific 

CO2 emission factor may be used, provided it is developed using methods outlined in § 98.404.

Where:

CO2n = Annual CO2 mass emissions that would result from the combustion or 

oxidation of natural gas received that bypassed the city gate and is not 

otherwise accounted for by Equation NN-1 or NN-2 of this section (metric 

tons).

Fuelz = Total annual volume of natural gas received that was not otherwise accounted 

for by Equation NN-1 or NN-2 of this section (natural gas from producers 

and natural gas processing plants from local production, or natural gas that 

was received as a liquid, vaporized and delivered, and any other source that 

bypassed the city gate). (Mscf per year)

EFz = Fuel-specific CO2 emission factor (MT CO2/Mscf)

(4) Calculate the total CO2 emissions that would result from the complete combustion or 

oxidation of the annual supply of natural gas to end-users that receive a supply less than 460,000 

Mscf per year using Equation NN-6 of this section.
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Where:

CO2 = Annual CO2 mass emissions that would result from the combustion or 

oxidation of natural gas delivered to LDC end-users not covered in paragraph 

(b)(2) of this section (metric tons).

CO2i = Annual CO2 mass emissions that would result from the combustion or 

oxidation of natural gas received at the city gate as calculated in paragraph 

(a)(1) or (2) of this section (metric tons).

CO2j = Annual CO2 mass emissions that would result from the combustion or 

oxidation of natural gas delivered to transmission pipelines or other LDCs as 

calculated in paragraph (b)(1) of this section (metric tons).

CO2k = Annual CO2 mass emissions that would result from the combustion or 

oxidation of natural gas delivered to each large end-user as calculated in 

paragraph (b)(2) of this section (metric tons).

CO2l = Annual CO2 mass emissions that would result from the combustion or 

oxidation of the net change in natural gas stored by the LDC within the 

reported year as calculated in paragraph (b)(3)(i) of this section (metric tons).

CO2n = Annual CO2 mass emissions that would result from the combustion or 

oxidation of natural gas that was received by the LDC directly from sources 

bypassing the city gate, and is not otherwise accounted for in Equation NN-1 

or NN-2 of this section, as calculated in paragraph (b)(3)(ii) of this section 

(metric tons).

(c) Each NGL fractionator shall follow the following procedures.

(1)(i) For fractionated NGLs received by the reporter from other NGL fractionators, you 

shall use Equation NN-7 of this section and the default values for the CO2 emission factors found 

in Table NN-2 of this subpart.

(ii) Alternatively, reporter-specific CO2 emission factors may be used, provided they are 

developed using methods outlined in § 98.404.

Where:
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CO2m = Annual CO2 mass emissions that would result from the combustion or 

oxidation of each fractionated NGL product “g” received from other 

fractionators (metric tons).

Fuelg = Total annual volume of each NGL product “g” received from other 

fractionators (bbls).

EFg = Fuel-specific CO2 emission factor of NGL product “g” (MT CO2/bbl).

(2) Calculate the total CO2 equivalent emissions that would result from the combustion or 

oxidation of fractionated NGLs supplied less the quantity received from other fractionators using 

Equation NN-8 of this section.

Where:

CO2 = Annual CO2 mass emissions that would result from the combustion or 

oxidation of fractionated NGLs delivered to customers or on behalf of 

customers less the quantity received from other fractionators (metric tons).

CO2i = Annual CO2 mass emissions that would result from the combustion or 

oxidation of fractionated NGLs delivered to all customers or on behalf of 

customers as calculated in paragraph (a)(1) or (a)(2) of this section (metric 

tons).

CO2m = Annual CO2 mass emissions that would result from the combustion or 

oxidation of fractionated NGLs received from other fractionators and 

calculated in paragraph (c)(1) of this section (metric tons).

§ 98.404 Monitoring and QA/QC requirements.

(a) Determination of quantity. (1) NGL fractionators and LDCs shall determine the 

quantity of NGLs and natural gas using methods in common use in the industry for billing 

purposes as audited under existing Sarbanes Oxley regulation.

(i) Where an appropriate standard method published by a consensus-based standards 

organization exists, such a method shall be used. Consensus-based standards organizations 

include, but are not limited to, the following: ASTM International, the American National 

Standards Institute (ANSI), the American Gas Association (AGA), the American Society of 
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Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North 

American Energy Standards Board (NAESB).

(ii) Where no appropriate standard method developed by a consensus-based standards 

organization exists, industry standard practices shall be followed.

(2) NGL fractionators and LDCs shall base the minimum frequency of the product 

quantity measurements, to be summed to the annual quantity reported, on the reporter's standard 

practices for commercial operations.

(i) For NGL fractionators the minimum frequency of measurements shall be the 

measurements taken at custody transfers summed to the annual reportable volume.

(ii) For natural gas the minimum frequency of measurement shall be based on the LDC's 

standard measurement schedules used for billing purposes and summed to the annual reportable 

volume.

(3) NGL fractionators shall use measurement for NGLs at custody transfer meters or at 

such meters that are used to determine the NGL product slate delivered from the fractionation 

facility.

(4) If a NGL fractionator supplies a product that is a mixture or blend of two or more 

products listed in Tables NN-1 and NN-2 of this subpart, the NGL fractionator shall report the 

quantities of the constituents of the mixtures or blends separately.

(5) For an LDC using Equation NN-1 or NN-2 of this subpart, the point(s) of 

measurement for the natural gas volume received shall be the LDC city gate meter(s).

(i) If the LDC makes its own quantity measurements according to established business 

practices, its own measurements shall be used.
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(ii) If the LDC does not make its own quantity measurements according to established 

business practices, it shall use its delivering pipeline invoiced measurements for natural gas 

deliveries to the LDC city gate, used in determining daily system sendout.

(6) An LDC using Equation NN-3 of this subpart shall measure natural gas at the custody

transfer meters.

(7) An LDC using Equation NN-4 of this subpart shall measure natural gas at the large 

end-user's meter(s). Where a large end-user is known to have more than one meter located at 

their facility, based on readily available information in the LDCs possession, the reporter shall 

measure the natural gas at each meter and sum the annual volume delivered to all meters located 

at the end-user's facility to determine the total volume delivered to the large end-user. Otherwise, 

the reporter shall consider the total annual volume delivered through each single meter at a single 

particular location to be the volume delivered to an individual large end-user.

(8) An LDC using Equation NN-5a and/or NN-5b of this subpart shall measure natural 

gas as follows:

(i) Fuel1 shall be measured at the on-system storage injection meters and/or at the meters 

measuring natural gas to be liquefied.

(ii) Fuel2 shall be measured at the meters used for measuring on-system storage 

withdrawals and/or LNG vaporization injection.

(iii) Fuelz shall be measured using established business practices.

(9) An LDC shall measure all natural gas under the following standard industry

temperature and pressure conditions: Cubic foot of gas at a temperature of 60 degrees Fahrenheit 

and at an absolute pressure of one atmosphere.
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(b) Determination of higher heating values (HHV). (1) When a reporter uses the default 

HHV provided in this section to calculate Equation NN-1 of this subpart, the appropriate value 

shall be taken from Table NN-1 of this subpart.

(2) When a reporter uses a reporter-specific HHV to calculate Equation NN-1 of this 

subpart, an appropriate standard test published by a consensus-based standards organization shall 

be used. Consensus-based standards organizations include, but are not limited to, the following: 

AGA and GPA.

(i) If an LDC makes its own HHV measurements according to established business 

practices, then its own measurements shall be used.

(ii) If an LDC does not make its own measurements according to established business 

practices, it shall use its delivering pipeline measurements.

(c) Determination of emission factor (EF). (1) When a reporter used the default EF 

provided in this section to calculate Equation NN-1 of this subpart, the appropriate value shall be 

taken from Table NN-1 of this subpart.

(2) When a reporter used the default EF provided in this section to calculate Equation 

NN-2, NN-3, NN-4, NN-5a, NN-5b, or NN-7 of this subpart, the appropriate value shall be taken 

from Table NN-2 of this subpart.

(3) When a reporter uses a reporter-specific EF, the reporter shall use an appropriate 

standard method published by a consensus-based standards organization to conduct 

compositional analysis necessary to determine reporter-specific CO2 emission factors. 

Consensus-based standards organizations include, but are not limited to, the following: AGA and 

GPA.
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(d) Equipment Calibration. (1) Equipment used to measure quantities in Equations NN-1, 

NN-2, NN-5a and NN-5b of this subpart shall be calibrated prior to its first use for reporting 

under this subpart, using a suitable standard method published by a consensus based standards 

organization or according to the equipment manufacturer's directions.

(2) Equipment used to measure quantities in Equations NN-1, NN-2, NN-5a, and NN-5b 

of this subpart shall be recalibrated at the frequency specified by the standard method used or by 

the manufacturer's directions.

(3) Equipment used to measure quantities in Equations NN-3 and NN-4 of this subpart 

shall be recalibrated at the frequency commonly used within the industry.

§ 98.405 Procedures for estimating missing data.

(a) Whenever a quality-assured value of the quantity of natural gas liquids or natural gas 

supplied during any period is unavailable (e.g., if a flow meter malfunctions), a substitute data 

value for the missing quantity measurement must be used in the calculations according to 

paragraphs (b) and (c) of this section.

(b) Determination of quantity. (1) NGL fractionators shall substitute meter records 

provided by pipeline(s) for all pipeline receipts of NGLs; by manifests for deliveries made to 

trucks or rail cars; or metered quantities accepted by the entities purchasing the output from the 

fractionator whether by pipeline or by truck or rail car. In cases where the metered data from the 

receiving pipeline(s) or purchasing entities are not available, fractionators may substitute 

estimates based on contract quantities required to be delivered under purchase or delivery

contracts with other parties.
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(2) LDCs shall either substitute their delivering pipeline metered deliveries at the city 

gate or substitute nominations and scheduled delivery quantities for the period when metered 

values of actual deliveries are not available.

(c) Determination of HHV and EF. (1) Whenever an LDC that makes its own HHV 

measurements according to established business practices cannot follow the quality assurance 

procedures for developing a reporter-specific HHV, as specified in § 98.404, during any period 

for any reason, the reporter shall use either its delivering pipeline measurements or the default 

HHV provided in Table NN-1 of this part for that period.

(2) Whenever an LDC that does not make its own HHV measurements according to 

established business practices or an NGL fractionator cannot follow the quality assurance 

procedures for developing a reporter-specific HHV, as specified in § 98.404, during any period 

for any reason, the reporter shall use the default HHV provided in Table NN-1 of this part for 

that period.

(3) [Reserved]

(4) Whenever a reporter cannot follow the quality assurance procedures for developing a 

reporter-specific EF, as specified in § 98.404, during any period for any reason, the reporter shall 

use the default EF provided in § 98.408 for that period.

§ 98.406 Data reporting requirements.

(a) In addition to the information required by § 98.3(c), the annual report for each NGL 

fractionator covered by this rule shall contain the following information.

(1) Annual quantity (in barrels) of each NGL product supplied (including fractionated 

NGL products received from other NGL fractionators) in the following product categories: 
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ethane, propane, normal butane, isobutane, and pentanes plus (Fuelh in Equations NN-1 and NN2).

(2) Annual quantity (in barrels) of each NGL product received from other NGL 

fractionators in the following product categories: ethane, propane, normal butane, isobutane, and 

pentanes plus (Fuelg in Equation NN-7).

(3) Annual volumes in Mscf of natural gas received for processing.

(4) Annual quantities (in barrels) of y-grade, o-grade, and other bulk NGLs:

(i) Received.

(ii) Supplied to downstream users that are not fractionated by the reporter.

(5) Annual quantity (in barrels) of propane that the NGL fractionator odorizes at the 

facility and delivers to others.

(6) Annual CO2 emissions (metric tons) that would result from the complete combustion 

or oxidation of the quantities in paragraphs (a)(1) and (a)(2) of this section, calculated in 

accordance with § 98.403(a) and (c)(1).

(7) Annual CO2 mass emissions (metric tons) that would result from the combustion or 

oxidation of fractionated NGLs supplied less the quantity received from other fractionators, 

calculated in accordance with § 98.403(c)(2). If the calculated value is negative, the reporter 

shall report the value as zero.

(8) The specific industry standard used to measure each quantity reported in paragraph 

(a)(1) of this section.

(9) If the NGL fractionator developed reporter-specific EFs or HHVs, report the 

following for each product type:
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(i) The specific industry standard(s) used to develop reporter-specific higher heating 

value(s) and/or emission factor(s), pursuant to § 98.404(b)(2) and (c)(3).

(ii) The developed HHV(s).

(iii) The developed EF(s).

(b) In addition to the information required by § 98.3(c), the annual report for each LDC 

shall contain the following information.

(1) Annual volume in Mscf of natural gas received by the LDC at its city gate stations for 

redelivery on the LDC's distribution system, including for use by the LDC (Fuelh in Equations 

NN-1 and NN-2).

(2) Annual volume in Mscf of natural gas placed into storage or liquefied and stored 

(Fuel1 in Equation NN-5a).

(3) Annual volume in Mscf of natural gas withdrawn from on-system storage and annual 

volume in Mscf of vaporized liquefied natural gas (LNG) withdrawn from storage for delivery

on the distribution system (Fuel2 in Equation NN-5a).

(4) [Reserved]

(5) Annual volume in Mscf of natural gas that bypassed the city gate(s) and was supplied 

through the LDC distribution system. This includes natural gas from producers and natural gas 

processing plants from local production, or natural gas that was vaporized upon receipt and 

delivered, and any other source that bypassed the city gate (Fuelz in Equation NN-5b).

(6) Annual volume in Mscf of natural gas delivered to downstream gas transmission 

pipelines and other local distribution companies (Fuel in Equation NN-3).

(7) Annual volume in Mscf of natural gas delivered by the LDC to each large end-user as 

defined in § 98.403(b)(2)(i) of this section.
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(8) The total annual CO2 mass emissions (metric tons) associated with the volumes in 

paragraphs (b)(1) through (b)(7) of this section, calculated in accordance with § 98.403(a) and 

(b)(1) through (b)(3).

(9) Annual CO2 emissions (metric tons) that would result from the complete combustion 

or oxidation of the annual supply of natural gas to end-users registering less than 460,000 Mscf, 

calculated in accordance with § 98.403(b)(4). If the calculated value is negative, the reporter 

shall report the value as zero.

(10) The specific industry standard used to develop the volume reported in paragraph 

(b)(1) of this section.

(11) If the LDC developed reporter-specific EFs or HHVs, report the following:

(i) The specific industry standard(s) used to develop reporter-specific higher heating 

value(s) and/or emission factor(s), pursuant to § 98.404 (b)(2) and (c)(3).

(ii) The developed HHV(s).

(iii) The developed EF(s).

(12) For each large end-user reported in paragraph (b)(7) of this section, report:

(i) The customer name, address, and meter number(s).

(ii) Whether the quantity of natural gas reported in paragraph (b)(7) of this section is the 

total quantity delivered to a large end-user's facility, or the quantity delivered to a specific meter 

located at the facility.

(iii) If known, report the EIA identification number of each LDC customer.

(13) The annual volume in Mscf of natural gas delivered by the LDC (including natural 

gas that is not owned by the LDC) to each of the following end-use categories. For definitions of 
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these categories, refer to EIA Form 176 (Annual Report of Natural Gas and Supplemental Gas 

Supply & Disposition) and Instructions.

(i) Residential consumers.

(ii) Commercial consumers.

(iii) Industrial consumers.

(iv) Electricity generating facilities.

(14) The name of the U.S. state or territory covered in this report submission.

(c) Each reporter shall report the number of days in the reporting year for which 

substitute data procedures were used for the following purpose:

(1) To measure quantity.

(2) To develop HHV(s).

(3) To develop EF(s).

§ 98.407 Records that must be retained.

In addition to the information required by § 98.3(g), the reporter shall retain the following 

records:

(a) Records of all meter readings and documentation to support volumes of natural gas 

and NGLs that are reported under this part.

(b) Records documenting any estimates of missing metered data and showing the 

calculations of the values used for the missing data.

(c) Calculations and worksheets used to estimate CO2 emissions for the volumes reported 

under this part.

(d) Records related to the large end-users identified in § 98.406(b)(7).
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(e) Records relating to measured Btu content or carbon content showing specific industry

standards used to develop reporter-specific higher heating values and emission factors.

(f) Records of such audits as required by Sarbanes Oxley regulations on the accuracy of 

measurements of volumes of natural gas and NGLs delivered to customers or on behalf of 

customers.

§ 98.408 Definitions.

All terms used in this subpart have the same meaning given in the Clean Air Act and 

subpart A of this part.

Table NN-1 to Subpart NN of Part 98—Default Factors for Calculation Methodology 1 of 

This Subpart

Fuel Default higher heating value1

Default CO2

emission

factor

(kg CO2/MMBtu)

Natural Gas 1.026 MMBtu/Mscf 53.06

Propane 3.84 MMBtu/bbl 62.87

Normal butane 4.34 MMBtu/bbl 64.77

Ethane 2.85 MMBtu/bbl 59.60

Isobutane 4.16 MMBtu/bbl 64.94

Pentanes plus 4.62 MMBtu/bbl 70.02

1 Conditions for higher heating values presented in MMBtu/bbl are 60 °F and saturation pressure.

Table NN-2 to Subpart NN of Part 98—Default Factors for Calculation Methodology 2 of 

This Subpart

Fuel Unit

Default CO2 emission factor

(MT CO2/Unit)1

Natural Gas Mscf 0.0544

Propane Barrel 0.241

Normal butane Barrel 0.281

Ethane Barrel 0.170

Isobutane Barrel 0.270

Pentanes plus Barrel 0.324

1 Conditions for emission value presented in MT CO2/bbl are 60 °F and saturation pressure.
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