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 consitutent cons t ituent 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 tha t 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) deliver ing 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 th at 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 sh all, 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 orPage 3 of 24 oxidation of the products supplied using either of Calculation Methodology 1 or 2 of this subpart: (1) Calcul ation Methodology 1
. NGL fractionators shall estimate CO 2 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 CO 2 emissions that would result from the com plete 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 CO 2 emission factor in Table NN

– 1 of this subpart. Alternatively, for each product, a reporter

- specific higher heating value and CO 2 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:
CO 2 i = Annual CO 2

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

EF h = CO 2 emission factor of product “h” (kg CO 2 1 x 10 / MMBtu). −3 (2) = Conversion factor from kilograms to metric tons (MT/kg). Calculation Methodology 2 . NGL fractionators shall estimate CO 2 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 CO 2 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 CO 2 emission factor found in Table NN
– 2 of this subpart. Alternatively, for each product, a reporter
- specific CO 2 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:
CO 2 i = Annual CO 2

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 Mscf volume per year ) , in Mscf for natural gas and bbl for NGLs ).
h = CO 2 emission factor of product “h” (MT CO 2 / bbl, or MT CO 2 (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 eEquation Equation NN
– 3 of this section and the default values for the CO 2 emission f actors found in Table NN

– 2 of this subpart. Alternatively, reporter

- specific CO 2 emission factors may be used, provided they are developed using methods outlined in §98.404.

Where:
CO 2 j = Annual CO 2

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 CO 2 emission factor (MT CO 2 (2)(i) For natural gas delivered to each meter end

- users registering a supply equal to or greater than 460,000 Mscf per year, use Equation NN

– 4 of this section and the default values for the CO / Mscf).

2 (ii) Alternatively, reporter

- specific CO emission factors found in Table NN

– 2 of this subpart.

2 em ission factors may be used, provided they are developed using methods outlined in §98.404.

Where:Page 6 of 24
CO 2 k = Annual CO 2

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 by delivered to each end

- user s that receive s a supply equal to or greater than 460,000 Mscf per year (metric tons).

EF = Fuel

- specific CO 2 emission fact or (MT CO 2 (3) For the net change in natural gas stor ed on system by the LDC during the reporting year , us e E quation NN

- 5a of this section
. F or natural gas that is received by the LDC at 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
. / 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 use d for deliveries , use Equation NN

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

– 2 of this subpart. Alternatively, a reporter
- specific CO 2

CO 2 l = [ Fuel 1 − Fuel 2 ] ∗ EF (Eq. NN

- 5a) emission factor may be used, provided it is developed using methods outline d in §98.404.

Where:
CO 2 l = Annual CO 2 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 deliveries on system by Formatted: CenteredPage 7 of 24
the LDC within the reported report ing year (metric tons). Fuel 1

Fuel = Total annual volume of natural gas received by the LDC at the city gate and stored added to stor age 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 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 . 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 in to/removed from storage (MT CO 2 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 CO 2 emission factor may be used, provided it is developed using methods outlined in §98.404.Page 8 of 24
CO 2 n = Fuel z ∗ EF z (Eq. NN

- 5b) Where:
CO 2n = Annual CO 2

Fuel mass emissions that would result from the combustion or oxidation of natural gas received that bypassed the city gate and is not o therwise accounted for by Equation NN

1 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 CO 2 emission factor (MT CO 2 /Mscf)
(4) Calculate the total CO 2 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.

CO 2 = CO 2 i + CO 2 n − CO 2 j − ∑ CO 2 k − CO 2 l (Eq. NN

- 6) Where:
CO 2 = Annual CO 2

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 sec tion (metric tons).
2 i CO 2 i = Annual CO 2 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
CO 2 j CO 2 j = Annual CO 2

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 CO 2

CO mass emissions that would result from the comb ustion or oxidation of natural gas received by delivered to each end

- user s that receive s a supply equal to or greater than 460,000 Mscf per year as calculated in paragraph (b)(2) of this section (metric tons).
2 l CO 2 l = Annual CO 2

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 CO 2

(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 but is not used otherwise accounted for deliveries within the reported year in 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 fractio nators, you shall use Equation NN

– 7 of this section and the default values for the CO 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.Page 10 of 24

Where:
CO 2 m = Annual CO 2

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” rec eived (bbls).

g = Fuel

- specific CO 2 emission factor of NGL product “g” (MT CO 2 (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 by from other fractionators using Equation NN

– 8 of this section.

Where:
CO 2 = Annual CO 2

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 fr actionators (metric tons).
2 i = Annual CO 2

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).
2 m = Annual CO 2 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 appropria te 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 Instit ute (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
con sensus - 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 measur ement 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 determi ne 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 supplied received shall be the LDC cit y 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 customer end

- user ’s meter ( s ) . Where an end

- user is known to have more than one meter located at their facility, t he 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 a each single particluar meter at a single particular location as to be the the volume delivered to an individual end

- user. (8) An LDC using Equation NN

– 5 5 a and/ or NN
- 5b of this subpart shall measure natural gas as follows: (i) Fuel 1

(ii) Fuel shall be measured at the on

- system storage inje ction 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 Fuel 2

(iii) Fuel is from a source other than storage, the appropr iate 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) pou nds per square inch one 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 busin ess 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, thePage 15 of 24 appropriate value shall be taken f rom 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

– 5 5 a, 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 CO 2

(d) Equipment Calibration. emission factors. Consensus

- b ased 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, a nd 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 fr equency 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 wher e 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 nominationsPage 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) Whe never 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 shal l 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 can not 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 fr actionator 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 specifiedPage 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 per iod.

(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 produ ct 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 cate gories: ethane, propane, normal butane, isobutane, and pentanes plus. (3) Annual volumes in Mscf of natural gas received for processing. (4) Annual quantit ies y (in barrels) of y

- grade, o - grad e , and other bulk NGLs received from others for fractionation. : ( i) R eceived. (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 CO 2

(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 stan dard 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 by 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.

(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 t he 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 (Fuel 1 (3) Annual volume in Mscf of natural gas withdrawn from on

system storage and annual volume in Mscf of vaporized liquefied natural gas (LNG) produced at on

- system vaporization facilities withdrawn from storage for delivery on the distribution system (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 on system storage (that is not delivered to bypassed 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 or and natura l 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 (Fuel z (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 LDCPage 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 Mcsf Ms c f during the calendar year. (8) The total annual CO 2

(9) Annual CO mass emissions (metric tons) associated wit h 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
o f natural gas to end

- users registering less than 460,000 Mcsf M sc f , 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), pursuan t 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 Instruction s. (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 foll owing 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 contain the reporter shall retain the following informa tion records : § 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 CO 2
(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 conte nt 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 del ivered 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 HH**  **NN of Part 98**  **— Default Factors for**  **Calculation Methodolo gy 1 of This Subpart** 

**Fuel Default**  **high high**  **er heating**  **value factor**  **value Default**  CO

1 2 **emission factor**  **(kg** CO 2 Natural Gas / **MMBtu)** 1. 028 02 6 MMBtu/Mscf 53. 02 0 6 Propane 3.82 2 3.84 MMBtu/bbl 61.46 62.87 Normal butane 4. 242 4.34 MMBtu/bbl 65.15 64.77
Ethane 4.032 2.8 5 MMBtu/bbl 62.64 59.60 Isobutane 4. 074 1 6 MMBtu/bbl 64.91 64.94 Pentanes plus 4.62 0 MMBtu/bbl 70.02
1 Conditions for h igher heating values presented in MMBtu/bbl are 60 oF and saturation pressure
. **Table NN –**  **2 to Subpart HH**  **NN of Part 98**  **— Lookup**  **Default Values for**  **Calculation Methodology 2 of This Subpart**

**Fuel Unit**  **Default** CO 2 **emission value (MT**  CO 2 / **Unit)** Natural Gas 1 Mscf 0. 055 054 4 Propane Barrel 0. 235 241 Normal butane Barrel 0. 276 281 Ethane Barrel 0. 253 170 Isobutane Barrel 0. 266 270 Pentanes plus Barrel 0.324 1 Conditions for emission value presented in MT CO 2 /bbl are 60 oF and saturation pressure.