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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.
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(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.

Any supplier of natural gas and natural gas liquids that 

meets the requirements of §98.2(a)(4) must report GHG emissions.

§ 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 
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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. LDCs shall estimate CO2 emissions 

that would result from the complete combustion or oxidation of 

the product received at the city gate using Equation NN–1. 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:

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

CO2/MMBtu).

1 x 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. LDCs shall estimate CO2 emissions 

that would result from the complete combustion or oxidation of 

the product received at the city gate using Equation NN–2. 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 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:

CO2 i = 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.
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(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:

CO2 j = 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 

(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 

end-user means any end-user facility receiving greater than or 

equal to 460,000 Mscf of natural gas 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.
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(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.
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 = [ − 

] ∗  (Eq. NN-5a)

Where:

CO2l = Annual CO2 mass emissions that would result 

from the combustion or oxidation of the net 

change in natural gas stored on system by the 

LDC within the reporting year (metric tons).

Fuel1 = Total annual volume of natural gas added to 

storage on-system or liquefied and stored in 

the reporting year (Mscf per year).

Fuel2 = Total annual volume of natural gas that is 

removed from storage or vaporized and removed 

from storage and used for deliveries to 

customers or other LDCs by the LDC within the 

reporting year (Mscf per year).

EF = Annual average CO2 emission factor for natural 

gas placed into/removed from storage (MT 

CO2/Mscf).

(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.

 =  ∗  (Eq. NN-5b)

Where:
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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 NN1 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.

 =  +  −  − ∑  −  (Eq. NN-6)

Where:

CO2 = Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural 

gas delivered to LDC end-users not covered in 

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

tons).

CO2i = Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural 

gas received at the city gate as calculated in 

paragraph (a)(1) or (a)(2) of this section 

(metric tons).

CO2j = Annual CO2 mass emissions that would result 

from the combustion or oxidation of natural 

gas delivered to transmission pipelines or 
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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 (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 
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industry for billing purposes as audited under existing Sarbanes 

Oxley regulationn.

(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 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.
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(3) NGL fractionators shall use measurement for NGLs at 

custody tranfer 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 not listed in 

Table NN–1 of this subpart 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.

(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
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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.

(b) Determination of higher heating values (HHV).
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(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.
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(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.

(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 
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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.

(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 
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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 to downstream facilities in the following product 

categories: ethane, propane, normal butane, isobutane, and 

pentanes plus.

(2) Annual quantity (in barrels) of each NGL product 

received from other NGL fractionators in the following product 
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categories: ethane, propane, normal butane, isobutane, and 

pentanes plus.

(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.

(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 onsystem 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).
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(6) Annual volume in Mscf of natural gas delivered to 

downstream gas transmission pipelines and other local 

distribution companies.

(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.

(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).
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(12) The customer name, address, and meter number of each 

large end-user reported in paragraph (b)(7) of this section. 

Additionally, report whether the quantity of natural gas 

reported in paragraph (b)(7) of this section is the total 

quantity delivered to a large end-user’s facility, or the 

quantity delivered to a specific meter located at the facility.

(i) If known, report the EIA identification number of each 

LDC customer.

(ii) [Reserved]

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

the local distribution company to each of the following end-use 

categories. For definitions of 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.

(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).
Page 22 of 23

§ 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).

(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.
Page 23 of 23

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

60oF and saturation pressure.

Table NN–2 to Subpart NN of Part 98—Default Values for 

Calculation Methodology 2 of This Subpart

Fuel Unit

Default CO2

emission value

(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 60oF 

and saturation pressure.