Page 1 of 24

Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids

This supplier category consists of natural gas liquids 

fractionators and local natural gas distribution companies.

§ 98.400 Definition of the source category.

(a) Natural gas liquids fractionators are installations 

that fractionate natural gas liquids (NGLs) into their 

consitutentconstituent 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.
Page 2 of 24

(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.

Any supplier of natural gas and natural gas liquids that 

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

§ 98.401 Reporting threshold.

(a) NGL fractionators must report the CO

§ 98.402 GHGs to report.

2

(b) LDCs must report the CO

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.

2 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.

(a) LDCs and fractionators shall, for each individual 

product reported under this part, calculate the estimated CO

§ 98.403 Calculating GHG emissions.

2

emissions that would result from the complete combustion or 
Page 3 of 24

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

Fuel

mass emissions that would result 

from the combustion or oxidation of each 

product “h” for redelivery to all recipients 

(metric tons).

h

HHV

= Total annual volume of product “h” supplied 

(volume per year, in thousand standard cubic 

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

h = Higher heating value of product “h” supplied 

(MMBtu/Mscf or MMBtu/bbl).
Page 4 of 24

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

CO2

1 x 10

/MMBtu).

−3

(2) 

= Conversion factor from kilograms to metric 

tons (MT/kg).

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

Fuel

mass emissions that would result 

from the combustion or oxidation of each 

product “h” (metric tons)

h

EF

= Total annual volume of product “h” supplied 

(bbl or Mscfvolume per year), in Mscf for 

natural gas and bbl for NGLs).

h = CO2 emission factor of product “h” (MT CO2/bbl, 

or MT CO2

(b) Each LDC shall follow the procedures below.

/Mscf)
Page 5 of 24

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

downstream gas transmission pipelines and other local 

distribution companies, use eEquationEquation 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

Fuel = Total annual volume of natural gas supplied 

(Mscf per year).

mass emissions that would result 

from the combustion or oxidation of natural 

gas for redelivery to transmission pipelines 

or other LDCs (metric tons).

EF = Fuel-specific CO2 emission factor (MT 

CO2

(2)(i) For natural gas delivered to each meterend-users

registering a supply equal to or greater than 460,000 Mscf per 

year, use Equation NN–4 of this section and the default values 

for the CO

/Mscf).

2

(ii) Alternatively, reporter-specific CO

emission factors found in Table NN–2 of this subpart.

2 emission factors 

may be used, provided they are developed using methods outlined 

in §98.404.

Where:
Page 6 of 24

CO2 k = Annual CO2

Fuel = Total annual volume of natural gas supplied to 

this end-user, if known, otherwise, the annual 

volume supplied to this meter (Mscf per year).

mass emissions that would result 

from the combustion or oxidation of natural 

gas received bydelivered to each end-users

that receives a supply equal to or greater 

than 460,000 Mscf per year (metric tons).

EF = Fuel-specific CO2 emission factor (MT 

CO2

(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 the LDC atmeans 

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.

/Mscf).

(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–

55a 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

CO2l = [Fuel1 − Fuel2] ∗ EF (Eq. NN-5a)

emission factor may be used, provided it is 

developed using methods outlined in §98.404.

Where:

CO2 l = Annual CO2 mass emissions that would result 

from the combustion or oxidation of the net 

change in natural gas that is liquefied and/or 

stored and not used for deliverieson system by 

Formatted: Centered
Page 7 of 24

the LDC within the reportedreporting year 

(metric tons).

Fuel1

Fuel

= Total annual volume of natural gas received by 

the LDC at the city gate and storedadded to 

storage on-system or liquefied and stored in 

the reporting year (Mscf per year).

2

EF = Fuel-specific CO

= Total annual volume of natural gas that is 

used for deliveries in the reporting year that 

was not otherwise accounted for in Equation 

NN–1 or NN–2 of this section (Mscf per year). 

This primarily includes natural gas previously 

stored on-system or liquefied and stored that 

isremoved from storage or vaporized and

removed from storage and used for deliveries 

to customers or other LDCs by the LDC within 

the reporting year. This also includes natural 

gas that bypassed the city gate and was 

delivered directly to LDC systems from 

producers or natural gas processing plants 

from local production. (Mscf per year).

2

EF = Annual average CO

emission factor (MT CO2/Mscf)

2 emission factor for natural 

gas placed into/removed from storage (MT 

CO2

EF(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 CO

/Mscf).

2 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.
Page 8 of 24

CO2n = Fuelz ∗ EFz (Eq. NN-5b)

Where:

CO2n = Annual CO2

Fuel

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).

z =

EF

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)

z = 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.

CO2 = CO2i + CO2n − CO2j − ∑ CO2k − CO2l (Eq. NN-6)

Where:

CO2 = Annual CO2

CO

mass emissions that would result 

from the combustion or oxidation of natural 

gas delivered to LDC customers end-users not 

covered in paragraph (b)(2) of this section 

(metric tons).

2 iCO2i = 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).
Page 9 of 24

CO2 jCO2j = Annual CO2

CO

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).

2 k = Annual CO2

CO

mass emissions that would result 

from the combustion or oxidation of natural 

gas received bydelivered to each end-users

that receives a supply equal to or greater 

than 460,000 Mscf per year as calculated in 

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

tons).

2 lCO2l = Annual CO2

CO

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).

2n = Annual CO2

(c) Each NGL fractionator shall follow the following 

procedures.

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 

liquefied and/or stored butis not 

usedotherwise accounted for deliveries within 

the reported yearin Equation NN-1 or NN-2 of 

this section, as calculated in paragraph 

(b)(3)(ii) of this section (metric tons).

(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

(ii) Alternatively, reporter-specific CO

emission factors found 

in Table NN–2 of this subpart.

2 emission factors 

may be used, provided they are developed using methods outlined 

in §98.404.
Page 10 of 24

Where:

CO2m = Annual CO2

Fuel

mass emissions that would result 

from the combustion or oxidation of each 

fractionated NGL product “g” received from 

other fractionators (metric tons).

g

EF

= Total annual volume of each NGL product “g” 

received (bbls).

g = Fuel-specific CO2 emission factor of NGL 

product “g” (MT CO2

(2) Calculate the total CO

/bbl).

2 equivalent emissions that would 

result from the combustion or oxidation of fractionated NGLs 

supplied less the quantity received byfrom other fractionators 

using Equation NN–8 of this section.

Where:

CO2 = Annual CO2

CO

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).

2i = Annual CO2

CO

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).

2m = 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.
Page 11 of 24

(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 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.
Page 12 of 24

(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 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 

suppliedreceived 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.
Page 13 of 24

(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 customerend-user’s meter(s). Where an 

end-user is known to have more than one meter located at their 

facility, the reporter shall measure the natural gas at each 

meter and sum the annual volume delivered to all meters. The

located at the end-user’s facility to determine the total volume 

delivered to the end- user. Otherwise, the reporter shall 

consider the total annual volume delivered through aeach single 

particluar meter at a single particular location asto be the the 

volume delivered to an individual end-user.

(8) An LDC using Equation NN–55a and/or NN-5b of this 

subpart shall measure natural gas as follows:

(i) Fuel1

(ii) Fuel

shall be measured at the on-system storage 

injection meters and/or at the meters measuring natural gas to 

be liquefied.

2 shall be measured at the meters used for 

measuring on-system storage withdrawals and/or LNG vaporization 

injection. If Fuel2

(iii) Fuel

is from a source other than storage, the 

appropriate meter shall be used to measure the quantity

z shall be measured using established business 

practices.
Page 14 of 24

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

following standard industry temperature and pressure conditions: 

Cubic foot of gas at a temperature of 60 degrees Fahrenheit and 

at an absolute pressure of fourteen and seventy-three hundredths 

(14.73) pounds per square inchone atmosphere.

(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 
Page 15 of 24

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–55a, 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

(d) Equipment Calibration.

emission 

factors. Consensus-based standards organizations include, but 

are not limited to, the following: AGA and GPA.

(1) Equipment used to measure quantities in Equations NN–1, 

NN–2, NN–5a and NN–5-5b 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–5-5b of this subpart shall be recalibrated 

at the frequency specified by the standard method used or by the 

manufacturer's directions.
Page 16 of 24

(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.

(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.

§ 98.405 Procedures for estimating missing data.

(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 
Page 17 of 24

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) Whenever a 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 NGL 

fractionator 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 
Page 18 of 24

in §98.404, during any period for any reason, the reporter shall 

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

(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.

§ 98.406 Data reporting requirements.

(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 

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

pentanes plus.

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

processing.

(4) Annual quantitiesy (in barrels) of y-grade, o-grade, 

and other bulk NGLs received from others for fractionation.:

(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.
Page 19 of 24

(6) Annual CO2

(7) Annual CO

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).

2

(8) The specific industry standard used to measure each 

quantity reported in paragraph (a)(1) of this section.

mass emissions (metric tons) that would 

result from the combustion or oxidation of fractionated NGLs 

supplied less the quantity received byfrom other fractionators, 

calculated in accordance with §98.403(c)(2). If the calculated 

value is negative, the reporter shall report the value as zero.

(9) If the NGL fractionator developed reporter-specific EFs 

or HHVs, report the following for each product type:

(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.
Page 20 of 24

(2) Annual volume in Mscf of natural gas placed into 

storage. or liquefied and stored (Fuel1

(3) Annual volume in Mscf of natural gas withdrawn from onsystem storage and annual volume in Mscf of vaporized liquefied 

natural gas (LNG) produced at on-system vaporization 

facilitieswithdrawn from storage for delivery on the 

distribution system (Fuel

in Equation NN-5a).

2

(4) [Reserved]

in Equation NN-5a).

(5) Annual volume in Mscf of natural gas that is not 

accounted for in paragraph (b)(1) of this section.

(4) Annual volume in Mscf of natural gas withdrawn from onsystem storage (that is not delivered tobypassed the city 

gate(s)) for delivery on and was supplied through the LDC 

distribution system.

(5) Annual volume in Mscf of This includes natural gas 

delivered directly to LDC systems from producers orand 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

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

downstream gas transmission pipelines and other local 

distribution companies.

in Equation NN-5b).

(7) Annual volume in Mscf of natural gas delivered by the 

LDC to each end-user facility that received from the LDC 
Page 21 of 24

deliveries equal to or greater than 460,000 Mscf during the 

calendar year, if known; otherwise, report the annual volume in 

Mscf of natural gas delivered by the LDC to each meter 

registering supply equal to or greater than 460,000 McsfMscf

during the calendar year.

(8) The total annual CO2

(9) Annual CO

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).

2

(10) The specific industry standard used to develop the 

volume reported in paragraph (b)(1) of this section.

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 

McsfMscf, calculated in accordance with §98.403(b)(4). If the 

calculated value is negative, the reporter shall report the 

value as zero.

(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).
Page 22 of 24

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

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

Additionally, report whether the quantity of natural gas 

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

quantity delivered to the end-user, or the quantity delivered to 

a specific meter.

(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 23 of 24

In addition to the information required by §98.3(g), each 

annual report must containthe reporter shall retain the 

following informationrecords:

§ 98.407 Records that must be retained.

(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

(d) Records related to the large end-users identified in 

§98.406(b)(7).

emissions for the volumes reported under this part.

(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.

All terms used in this subpart have the same meaning given 

in the Clean Air Act and subpart A of this part.

§ 98.408 Definitions.
Page 24 of 24

Table NN–1 to Subpart HHNN of Part 98—Default Factors for 

Calculation Methodology 1 of This Subpart

Fuel

Default highhigher heating value 

factorvalue

Default CO

1

2

emission 

factor

(kg CO2

Natural Gas

/MMBtu)

1.028026 MMBtu/Mscf 53.0206

Propane 3.8223.84 MMBtu/bbl 61.4662.87

Normal 

butane

4.2424.34 MMBtu/bbl 65.1564.77

Ethane 4.0322.85 MMBtu/bbl 62.6459.60

Isobutane 4.07416 MMBtu/bbl 64.9164.94

Pentanes 

plus

4.620 MMBtu/bbl 70.02

1 Conditions for higher heating values presented in MMBtu/bbl are

60oF and saturation pressure.

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

Calculation Methodology 2 of This Subpart

Fuel Unit

Default CO2

emission value

(MT CO2/Unit)

Natural Gas

1

Mscf 0.0550544

Propane Barrel 0.235241

Normal butane Barrel 0.276281

Ethane Barrel 0.253170

Isobutane Barrel 0.266270

Pentanes plus Barrel 0.324 1 Conditions for emission value presented in MT CO2/bbl are 60oF 

and saturation pressure.