Page 1 of 26

Subpart MM—Suppliers of Petroleum Products

§ 98.390 Definition of the source category.

This source category consists of petroleum refineries and importers and exporters of 

petroleum products and natural gas liquids as listed in Table MM-1 of this subpart.

(a) A petroleum refinery for the purpose of this subpart is any facility engaged in 

producing petroleum products through the distillation of crude oil.

(b) A refiner is the owner or operator of a petroleum refinery.

(c) Importer has the same meaning given in § 98.6 and includes any entity that imports 

petroleum products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or 

refiner of refined or semi-refined petroleum products shall be considered an importer if it 

otherwise satisfies the aforementioned definition.

(d) Exporter has the same meaning given in § 98.6 and includes any entity that exports 

petroleum products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or 

refiner of refined or semi-refined petroleum products shall be considered an exporter if it 

otherwise satisfies the aforementioned definition.

§ 98.391 Reporting threshold.

Any supplier of petroleum products who meets the requirements of § 98.2(a)(4) must 

report GHG emissions.

§ 98.392 GHGs To report.

Suppliers of petroleum products must report the CO2 emissions that would result from the 

complete combustion or oxidation of each petroleum product and natural gas liquid produced, 

used as feedstock, imported, or exported during the calendar year. Additionally, refiners must 
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report CO2 emissions that would result from the complete combustion or oxidation of any

biomass co-processed with petroleum feedstocks.

§ 98.393 Calculating GHG emissions.

(a) Calculation for individual products produced, imported, or exported. (1) Except as 

provided in paragraphs (h) and (i) of this section, any refiner, importer, or exporter shall 

calculate CO2 emissions from each individual petroleum product and natural gas liquid using 

Equation MM-1 of this section.

Where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each petroleum product or natural gas liquid “i” (metric tons).

Producti = Annual volume of product “i” produced, imported, or exported by the 

reporting party (barrels). For refiners, this volume only includes products ex 

refinery gate, and excludes products that entered the refinery but are not 

reported under § 98.396(a)(2). For natural gas liquids, volumes shall reflect 

the individual components of the product as listed in Table MM-1 to subpart 

MM.

EFi = Product-specific CO2 emission factor (metric tons CO2 per barrel).

(2) In the event that an individual petroleum product is produced as a solid rather than 

liquid any refiner, importer, or exporter shall calculate CO2 emissions using Equation MM-1 of 

this section.

Where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each petroleum product “i” (metric tons).

Producti = Annual mass of product “i” produced, imported, or exported by the reporting 

party (metric tons). For refiners, this mass only includes products ex refinery

gate, and excludes products that entered the refinery but are not reported 

under § 98.396(a)(2).
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EFi = Product-specific CO2 emission factor (metric tons CO2 per metric ton of 

product).

(b) Calculation for individual products that enter a refinery as a non-crude feedstock. (1) 

Except as provided in paragraphs (h) and (i) of this section, any refiner shall calculate CO2

emissions from each non-crude feedstock using Equation MM-2 of this section.

Where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each non-crude feedstock “j” (metric tons).

Feedstockj = Annual volume of a petroleum product or natural gas liquid “j” that enters the 

refinery to be further refined or otherwise used on site (barrels). For natural 

gas liquids, volumes shall reflect the individual components of the product as 

listed in table MM-1 of this subpart.

EFj = Feedstock-specific CO2 emission factor (metric tons CO2 per barrel).

(2) In the event that a non-crude feedstock enters a refinery as a solid rather than liquid, 

the refiner shall calculate CO2 emissions using Equation MM-2 of this section.

Where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each non-crude feedstock “j” (metric tons).

Feedstockj = Annual mass of a petroleum product “j” that enters the refinery to be further 

refined or otherwise used on site (metric tons).

EFj = Feedstock-specific CO2 emission factor (metric tons CO2 per metric ton of 

feedstock).

(c) Calculation for biomass co-processed with petroleum feedstocks. (1) Refiners shall 

calculate CO2 emissions from each type of biomass that enters a refinery and is co-processed 

with petroleum feedstocks using Equation MM-3 of this section.

Where:
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CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each type of biomass “m” (metric tons).

Biomassm = Annual volume of a specific type of biomass that enters the refinery and is 

co-processed with petroleum feedstocks to produce a petroleum product 

reported under paragraph (a) of this section (barrels).

EFm = Biomass-specific CO2 emission factor (metric tons CO2 per barrel).

(2) In the event that biomass enters a refinery as a solid rather than liquid and is coprocessed with petroleum feedstocks, the refiner shall calculate CO2 emissions from each type of 

biomass using Equation MM-3 of this section.

Where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each type of biomass “m” (metric tons).

Biomassm = Total annual mass of a specific type of biomass that enters the refinery to be 

co-processed with petroleum feedstocks to produce a petroleum product 

reported under paragraph (a) of this section (metric tons).

EFm = Biomass-specific CO2 emission factor (metric tons CO2 per metric ton of 

biomass).

(d) Summary calculation for refinery products. Refiners shall calculate annual CO2

emissions from all products using Equation MM-4 of this section.

Where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of all petroleum products and natural gas liquids (ex refinery gate) 

minus non-crude feedstocks and any biomass to be co-processed with 

petroleum feedstocks.

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each petroleum product or natural gas liquid “i” (metric tons).

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each non-crude feedstock “j” (metric tons).

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each type of biomass “m” (metric tons).
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(e) Summary calculation for importer and exporter products. Importers and exporters 

shall calculate annual CO2 emissions from all petroleum products and natural gas liquids 

imported or exported, respectively, using Equations MM-1 and MM-5 of this section.

Where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each petroleum product or natural gas liquid “i” (metric tons).

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of all petroleum products and natural gas liquids.

(f) Emission factors for petroleum products and natural gas liquids. The emission factor 

(EFi,j) for each petroleum product and natural gas liquid shall be determined using either of the 

calculation methods described in paragraphs (f)(1) or (f)(2) of this section. The same calculation 

method must be used for the entire quantity of the product for the reporting year. For refiners, the 

quantity of a product that enters a refinery (i.e., a non-crude feedstock) is considered separate 

from the quantity of a product ex refinery gate.

(1) Calculation Method 1. To determine the emission factor (i.e., EFi in Equation MM-1) 

for solid products, multiply the default carbon share factor (i.e., percent carbon by mass) in 

column B of Table MM-1 to this subpart for the appropriate product by 44/12. For all other 

products, use the default CO2 emission factor listed in column C of Table MM-1 of this subpart 

for the appropriate product.

(2) Calculation Method 2. (i) For solid products, develop emission factors according to 

Equation MM-6 of this section using a value of 1 for density and direct measurements of carbon 

share according to methods set forth in § 98.394(c). For all other products, develop emission 
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factors according to Equation MM-6 of this section using direct measurements of density and 

carbon share according to methods set forth in § 98.394(c).

Where:

EFi,j = Emission factor of the petroleum product or natural gas liquid (metric tons 

CO2 per barrel or per metric ton of product).

Density = Density of the petroleum product or natural gas liquid (metric tons per barrel 

for non-solid products, 1 for solid products).

Carbon share = Percent of total mass that carbon represents in the petroleum product or 

natural gas liquid, expressed as a fraction (e.g., 75% would be expressed as 

0.75 in the above equation).

44/12 = Conversion factor for carbon to carbon dioxide.

(ii) If you use a standard method that involves gas chromatography to determine the 

percent mass of each component in a product, calculate the product's carbon share using 

Equation MM-7 of this section.

Where:

Carbon Share = Percent of total mass that carbon represents in the petroleum product or 

natural gas liquid.

%Composition i* * *n = Percent of total mass that each molecular component in the 

petroleum product or natural gas liquid represents as determined by the 

procedures in the selected standard method.

%Massi* * *n = Percent of total mass that carbon represents in each molecular component 

of the petroleum product or natural gas liquid.

(g) Emission factors for biomass co-processed with petroleum feedstocks. Refiners shall 

use the most appropriate default CO2 emission factor (EFm) for biomass in Table MM-2 of this 

subpart to calculate CO2 emissions in paragraph (c) of this section.
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(h) Special procedures for blended biomass-based fuels. In the event that some portion of 

a petroleum product is biomass-based and was not derived by co-processing biomass and 

petroleum feedstocks together (i.e., the petroleum product was produced by blending a 

petroleum-based product with a biomass-based fuel), the reporting party shall calculate 

emissions for the petroleum product according to one of the methods in paragraphs (h)(1) 

through (h)(4) of this section, as appropriate.

(1) A reporter using Calculation Method 1 to determine the emission factor of a 

petroleum product shall calculate the CO2 emissions associated with that product using Equation 

MM-8 of this section in place of Equation MM-1 of this section.

Where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each petroleum product “i” (metric tons).

Producti = Annual volume of each petroleum product “i” produced, imported, or 

exported by the reporting party (barrels). For refiners, this volume only

includes products ex refinery gate.

EFi = Petroleum product-specific CO2 emission factor (metric tons CO2 per barrel) 

from Table MM-1 of this subpart.

%Voli = Percent volume of product “i” that is petroleum-based, not including any

denaturant that may be present in any ethanol product, expressed as a fraction 

(e.g., 75% would be expressed as 0.75 in the above equation).

(2) A refinery using Calculation Method 1 of this subpart to determine the emission 

factor of a non-crude petroleum feedstock shall calculate the CO2 emissions associated with that 

feedstock using Equation MM-9 of this section in place of Equation MM-2 of this section.

Where:
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CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each non-crude feedstock “j” (metric tons).

Feedstockj = Annual volume of each petroleum product “j” that enters the refinery as a 

feedstock to be further refined or otherwise used on site (barrels).

EFj = Non-crude petroleum feedstock-specific CO2 emission factor (metric tons 

CO2 per barrel).

%Volj = Percent volume of feedstock “j” that is petroleum-based, not including any 

denaturant that may be present in any ethanol product, expressed as a fraction 

(e.g., 75% would be expressed as 0.75 in the above equation).

(3) Calculation Method 2 procedures for products. (i) A reporter using Calculation 

Method 2 of this subpart to determine the emission factor of a petroleum product that does not 

contain denatured ethanol must calculate the CO2 emissions associated with that product using 

Equation MM-10 of this section in place of Equation MM-1 of this section.

where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each product “i” (metric tons).

Producti = Annual volume of each petroleum product “i” produced, imported, or 

exported by the reporting party (barrels). For refiners, this volume only

includes products ex refinery gate.

EFi = Product-specific CO2 emission factor (metric tons CO2 per barrel).

EFm = Default CO2 emission factor from Table MM-2 to subpart MM that most 

closely represents the component of product “i” that is biomass-based.

%Volm = Percent volume of petroleum product “i” that is biomass-based, expressed as 

a fraction (e.g., 75% would be expressed as 0.75 in the above equation).

(ii) In the event that a petroleum product contains denatured ethanol, importers and 

exporters must follow Calculation Method 1 procedures in paragraph (h)(1) of this section; and 

refineries must sample the petroleum portion of the blended biomass-based fuel prior to blending 

and calculate CO2 emissions using Equation MM-10a of this section.
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where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each biomass-blended fuel “i” (metric tons).

Productp = Annual volume of the petroleum-based portion of each biomass blended fuel 

“i” produced by the refiner (barrels).

EFi = Petroleum product-specific CO2 emission factor (metric tons CO2 per barrel).

(4) Calculation Method 2 procedures for non-crude feedstocks. (i) A refiner using 

Calculation Method 2 of this subpart to determine the emission factor of a non-crude petroleum 

feedstock that does not contain denatured ethanol must calculate the CO2 emissions associated 

with that feedstock using Equation MM-11 of this section in place of Equation MM-2 of this 

section.

where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of each non-crude feedstock “j” (metric tons).

Feedstockj = Annual volume of each petroleum product “j” that enters the refinery to be 

further refined or otherwise used on site (barrels).

EFj = Feedstock-specific CO2 emission factor (metric tons CO2 per barrel).

EFm = Default CO2 emission factor from Table MM-2 to subpart MM that most 

closely represents the component of petroleum product “j” that is biomassbased.

%Volm = Percent volume of non-crude feedstock “j” that is biomass-based, expressed 

as a fraction (e.g., 75% would be expressed as 0.75 in the above equation).

(ii) In the event that a non-crude feedstock contains denatured ethanol, refiners must 

follow Calculation Method 1 procedures in paragraph (h)(2) of this section.

(i) Optional procedures for blended products that do not contain biomass. (1) In the event 

that a reporter produces, imports, or exports a blended product that does not include biomass, the 

reporter may calculate emissions for the blended product according to the method in paragraph 
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(i)(2) of this section. In the event that a refiner receives a blended non-crude feedstock that does 

not include biomass, the refiner may calculate emission for the blended non-crude feedstock 

according to the method in paragraph (i)(3) of this section. The procedures in this section may be 

used only if all of the following criteria are met:

(i) The reporter knows the relative proportion of each component of the blend (i.e., the 

mass or volume percentage).

(ii) Each component of blended product “i” or blended non-crude feedstock “j” meets the 

strict definition of a product listed in Table MM-1 to subpart MM.

(iii) The blended product or non-crude feedstock is not comprised entirely of natural gas 

liquids.

(iv) The reporter uses Calculation Method 1.

(v) Solid components are blended only with other solid components.

(2) The reporter must calculate emissions for the blended product using Equation MM-12 

of this section in place of Equation MM-1 of this section.

where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of a blended product “i” (metric tons).

Blending Componenti...n = Annual volume or mass of each blending component that is 

blended (barrels or metric tons).

EFi...n = CO2 emission factors specific to each blending component (metric tons CO2

per barrel or per metric ton of product).

n = Number of blending components blended into blended product “i”.

(3) For refineries, the reporter must calculate emissions for the blended non-crude 

feedstock using Equation MM-13 of this section in place of Equation MM-2 of this section.
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where:

CO2. = Annual CO2 emissions that would result from the complete combustion or 

oxidation of a blended non-crude feedstock “j” (metric tons).

Blending Componenti...n = Annual volume or mass of each blending component that is 

blended (barrels or metric tons).

EFi...n = CO2 emission factors specific to each blending component (metric tons CO2

per barrel or per metric ton of product).

n = Number of blending components blended into blended non-crude feedstock 

“j”.

(4) For refineries, if a blending component “k” used in paragraph (i)(2) of this section 

enters the refinery before blending as non-crude feedstock:

(i) The emissions that would result from the complete combustion or oxidation of noncrude feedstock “k” must still be calculated separately using Equation MM-2 of this section and 

applied in Equation MM-4 of this section.

(ii) The quantity of blending component “k” applied in Equation MM-12 of this section 

and the quantity of non-crude feedstock “k” applied in Equation MM-2 of this section must be 

determined using the same method or practice.

§ 98.394 Monitoring and QA/QC requirements.

(a) Determination of quantity. (1) The quantity of petroleum products, natural gas liquids, 

and biomass, shall be determined as follows:

(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 
Page 12 of 26

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.

(iii) For products that are liquid at 60 degrees Fahrenheit and one standard atmosphere, 

all measurements of quantity shall be temperature-adjusted and pressure-adjusted to these 

conditions. For all other products, reporters shall use appropriate standard conditions specified in 

the standard method; if temperature and pressure conditions are not specified in the standard 

method or if a reporter uses an industry standard practice to determine quantity, the reporter shall 

use appropriate standard conditions according to established industry practices.

(2) All measurement equipment (including, but not limited to, flow meters and tank 

gauges) used for compliance with this subpart shall be appropriate for the standard method or 

industry standard practice followed under paragraph (a)(1)(i) or (a)(1)(ii) of this section.

(3) The annual quantity of crude oil received shall be determined according to one of the 

following methods. You may use an appropriate standard method published by a consensusbased standards organization or you may use an industry standard practice.

(b) Equipment Calibration. (1) All measurement equipment shall be calibrated prior to its 

first use for reporting under this subpart, using an appropriate standard method published by a 

consensus based standards organization or according to the equipment manufacturer's directions.

(2) Measurement equipment shall be recalibrated at the minimum frequency specified by

the standard method used or by the equipment manufacturer's directions.

(3) For units and processes that operate continuously with infrequent outages, it may not 

be possible to complete the calibration of a flow meter or other measurement device without 
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disrupting normal process operation. In such cases, the owner or operator may postpone the 

calibration until the next scheduled maintenance outage. The best available information from 

company records may be used in the interim. Such postponements shall be documented in the 

monitoring plan that is required under § 98.3(g)(5).

(c) Procedures for Calculation Method 2 of this subpart. (1) Reporting parties shall 

collect one sample of each petroleum product or natural gas liquid on any day of each calendar 

month of the reporting year in which the quantity of that product was measured in accordance 

with the requirements of this subpart. For example, if a given product was measured as entering 

the refinery continuously throughout the reporting year, twelve samples of that product shall be 

collected over the reporting year, one on any day of each calendar month of that year. If a given 

product was only measured from April 15 through June 10 of the reporting year, a refiner would 

collect three samples during that year, one during each of the calendar months of April, May and 

June on a day when the product was measured as either entering or exiting the refinery. Each 

sample shall be collected using an appropriate standard method published by a consensus-based 

standards organization.

(2) Mixing and handling of samples shall be performed using an appropriate standard 

method published by a consensus-based standards organization.

(3) Density measurement.

(i) For all products that are not solid, reporters shall test for density using an appropriate 

standard method published by a consensus-based standards organization.

(ii) The density value for a given petroleum product shall be generated by either making a 

physical composite of all of the samples collected for the reporting year and testing that single 

sample or by measuring the individual samples throughout the year and defining the 
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representative density value for the sample set by numerical means, i.e., a mathematical 

composite. If a physical composite is chosen as the option to obtain the density value, the

reporter shall submit each of the individual samples collected during the reporting year to the 

laboratory responsible for generating the composite sample.

(iii) For physical composites, the reporter shall handle the individual samples and the 

laboratory shall mix them in accordance with an appropriate standard method published by a 

consensus-based standards organization.

(iv) All measurements of density shall be temperature-adjusted and pressure-adjusted to 

the conditions assumed for determining the quantities of the product reported under this subpart.

(4) Carbon share measurement.

(i) Reporters shall test for carbon share using an appropriate standard method published 

by a consensus-based standards organization.

(ii) If a standard method that involves gas chromatography is used to determine the 

percent mass of each component in a product, the molecular formula for each component shall be 

obtained from the information provided in the standard method and the atomic mass of each 

element in a given molecular component shall be obtained from the periodic table of the 

elements.

(iii) The carbon share value for a given petroleum product shall be generated by either 

making a physical composite of all of the samples collected for the reporting year and testing that 

single sample or by measuring the individual samples throughout the year and defining the 

representative carbon share value for the sample set by numerical means, i.e., a mathematical 

composite. If a physical composite is chosen as the option to obtain the carbon share value, the 
Page 15 of 26

reporter shall submit each of the individual samples collected during the reporting year to the 

laboratory responsible for generating the composite sample.

(iv) For physical composites, the reporter shall handle the individual samples and the 

laboratory shall mix them in accordance with an appropriate standard method published by a 

consensus-based standards organization.

§ 98.395 Procedures for estimating missing data.

(a) Determination of quantity. Whenever the quality assurance procedures in § 98.394(a) 

cannot be followed to measure the quantity of one or more petroleum products, natural gas 

liquids, types of biomass, feedstocks, or crude oil during any period (e.g., if a meter 

malfunctions), the following missing data procedures shall be used:

(1) For quantities of a product that are purchased or sold, a period of missing data shall be 

substituted using a reporter's established procedures for billing purposes in that period as agreed 

to by the party selling or purchasing the product.

(2) For quantities of a product that are not purchased or sold but of which the custody is 

transferred, a period of missing data shall be substituted using a reporter's established procedures 

for tracking purposes in that period as agreed to by the party involved in custody transfer of the 

product.

(b) Determination of emission factor. Whenever any of the procedures in § 98.394(c) 

cannot be followed to develop an emission factor for any reason, Calculation Method 1 of this 

subpart must be used in place of Calculation Method 2 of this subpart for the entire reporting 

year.

§ 98.396 Data reporting requirements.

In addition to the information required by § 98.3(c), the following requirements apply:
Page 16 of 26

(a) Refiners shall report the following information for each facility:

(1) [Reserved]

(2) For each petroleum product or natural gas liquid listed in Table MM-1 of this subpart 

that enters the refinery to be further refined or otherwise used on site, report the annual quantity

in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components 

of the product.

(3) For each feedstock reported in paragraph (a)(2) of this section that was produced by 

blending a petroleum-based product with a biomass-based product, report the percent of the 

volume reported in paragraph (a)(2) of this section that is petroleum-based (excluding any 

denaturant that may be present in any ethanol product).

(4)-(5) [Reserved]

(6) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table 

MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, 

quantity shall reflect the individual components of the product. Petroleum products and natural 

gas liquids that enter the refinery, but are not reported in (a)(2), shall not be reported under this 

paragraph.

(7) For each product reported in paragraph (a)(6) of this section that was produced by

blending a petroleum-based product with a biomass-based product, report the percent of the 

volume reported in paragraph (a)(6) of this section that is petroleum-based (excluding any 

denaturant that may be present in any ethanol product).

(8) [Reserved]

(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation 

Method 2 of this subpart was used to determine an emissions factor, report:
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(i) The number of samples collected according to § 98.394(c)

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of 

product.

(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which 

Calculation Method 2 of this subpart was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of 

this section for which Calculation Method 2 of this subpart was used to determine an emissions 

factor, report:

(i) The number of samples collected according to § 98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of 

product.

(12) For every non-solid petroleum product and natural gas liquid reported in paragraph 

(a)(6) for which Calculation Method 2 was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.
Page 18 of 26

(13) [Reserved]

(14) For each specific type of biomass that enters the refinery to be co-processed with 

petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, 

report the annual quantity in metric tons or barrels.

(15) [Reserved]

(16) The CO2 emissions in metric tons that would result from the complete combustion or 

oxidation of each petroleum product and natural gas liquid (ex refinery gate) reported in 

paragraph (a)(6) of this section that were calculated according to § 98.393(a) or (h).

(17) The CO2 emissions in metric tons that would result from the complete combustion or 

oxidation of each feedstock reported in paragraph (a)(2) of this section that were calculated 

according to § 98.393(b) or (h).

(18) The CO2 emissions in metric tons that would result from the complete combustion or 

oxidation of each type of biomass feedstock co-processed with petroleum feedstocks reported in 

paragraph (a)(14) of this section, calculated according to § 98.393(c).

(19) The sum of CO2 emissions that would result from the complete combustion or 

oxidation of all products, calculated according to § 98.393(d).

(20) For all crude oil that enters the refinery, report the annual quantity in barrels.

(21) The quantity of bulk NGLs in metric tons or barrels received for processing during 

the reporting year. Report only quantities of bulk NGLs not reported in (a)(2) of this section.

(22) Volume of crude oil in barrels that you injected into a crude oil supply or reservoir.

(b) In addition to the information required by § 98.3(c), each importer shall report all of 

the following information at the corporate level:

(1) [Reserved]
Page 19 of 26

(2) For each petroleum product and natural gas liquid listed in Table MM-1 of this 

subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall 

reflect the individual components of the product.

(3) For each product reported in paragraph (b)(2) of this section that was produced by 

blending a petroleum-based product with a biomass-based product, report the percent of the 

volume reported in paragraph (b)(2) of this section that is petroleum-based (excluding any 

denaturant that may be present in any ethanol product).

(4) [Reserved]

(5) For each product reported in paragraph (b)(2) of this section for which Calculation 

Method 2 of this subpart used was used to determine an emissions factor, report:

(i) The number of samples collected according to § 98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of 

product.

(6) For each non-solid product reported in paragraph (b)(2) of this section for which 

Calculation Method 2 of this subpart was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO2 emissions in metric tons that would result from the complete combustion or 

oxidation of each imported petroleum product and natural gas liquid reported in paragraph (b)(2) 

of this section, calculated according to § 98.393(a).
Page 20 of 26

(8) The sum of CO2 emissions that would result from the complete combustion oxidation 

of all imported products, calculated according to § 98.393(e).

(c) In addition to the information required by § 98.3(c), each exporter shall report all of 

the following information at the corporate level:

(1) [Reserved]

(2) For each petroleum product and natural gas liquid listed in Table MM-1 of this 

subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall 

reflect the individual components of the product.

(3) For each product reported in paragraph (c)(2) of this section that was produced by

blending a petroleum-based product with a biomass-based product, report the percent of the 

volume reported in paragraph (c)(2) of this section that is petroleum based (excluding any 

denaturant that may be present in any ethanol product).

(4) [Reserved]

(5) For each product reported in paragraph (c)(2) of this section for which Calculation 

Method 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to § 98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percentmass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2 emissions factor in metric tons CO2 per barrel or per metric ton of 

product.

(6) For each non-solid product reported in paragraph (c)(2) of this section for which 

Calculation Method 2 of this subpart used was used to determine an emissions factor, report:
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(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO2 emissions in metric tons that would result from the complete combustion or 

oxidation of for each exported petroleum product and natural gas liquid reported in paragraph 

(c)(2) of this section, calculated according to § 98.393(a).

(8) The sum of CO2 emissions that would result from the complete combustion or 

oxidation of all exported products, calculated according to § 98.393(e).

(d) Blended non-crude feedstock and products. (1) Refineries, exporters, and importers 

must report the following information for each blended product and non-crude feedstock where 

emissions were calculated according to § 98.393(i):

(i) Volume or mass of each blending component.

(ii) The CO2 emissions in metric tons that would result from the complete combustion or 

oxidation of each blended non-crude feedstock or product, using Equation MM-12 or Equation 

MM-13 of this section.

(iii) Whether it is a blended non-crude feedstock or a blended product.

(2) For a product that enters the refinery to be further refined or otherwise used on site 

that is a blended non-crude feedstock, refiners must meet the reporting requirements of 

paragraph (a)(2) of this section by reflecting the individual components of the blended non-crude 

feedstock.

(3) For a product that is produced, imported, or exported that is a blended product, 

refiners, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), 

(b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the 

blended product.
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§ 98.397 Records that must be retained.

(a) All reporters shall retain copies of all reports submitted to EPA under § 98.396. In 

addition, all reporters shall maintain sufficient records to support information contained in those 

reports, including but not limited to information on the characteristics of their feedstocks and 

products.

(b) Reporters shall maintain records to support quantities that are reported under this 

subpart, including records documenting any estimations of missing data and the number of 

calendar days in the reporting year for which substitute data procedures were followed. For all 

reported quantities of petroleum products, natural gas liquids, and biomass, reporters shall 

maintain metering, gauging, and other records normally maintained in the course of business to 

document product and feedstock flows including the date of initial calibration and the frequency

of recalibration for the measurement equipment used.

(c) Reporters shall retain laboratory reports, calculations and worksheets used to estimate 

the CO2 emissions of the quantities of petroleum products, natural gas liquids, biomass, and 

feedstocks reported under this subpart.

(d) Reporters shall maintain laboratory reports, calculations and worksheets used in the 

measurement of density and carbon share for any petroleum product or natural gas liquid for 

which CO2 emissions were calculated using Calculation Method 2.

(e) Estimates of missing data shall be documented and records maintained showing the 

calculations.

(f) Reporters described in this subpart shall also retain all records described in § 98.3(g).

§ 98.398 Definitions.
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Except as specified in this section, all terms used in this subpart have the same meaning 

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

Bulk NGLs for purposes of reporting under this subpart means mixtures of NGLs that are 

sold or delivered as undifferentiated product.

Natural Gas Liquids (NGLs) for the purposes of reporting under this subpart means 

hydrocarbons that are separated from natural gas as liquids through the process of absorption, 

condensation, adsorption, or other methods, and are sold or delivered as differentiated product. 

Generally, such liquids consist of ethane, propane, butanes, or pentanes plus.

Table MM-1 to Subpart MM of Part 98—Default Factors for Petroleum Products and 

Natural Gas Liquids1 2

Products

Column A: density

(metric tons/bbl)

Column B:

carbon share

(% of mass)

Column C:

emission factor

(metric tons CO2/bbl)

Finished Motor Gasoline

Conventional—Summer

Regular 0.1181 86.66 0.3753

Midgrade 0.1183 86.63 0.3758

Premium 0.1185 86.61 0.3763

Conventional—Winter

Regular 0.1155 86.50 0.3663

Midgrade 0.1161 86.55 0.3684

Premium 0.1167 86.59 0.3705

Reformulated—Summer

Regular 0.1167 86.13 0.3686

Midgrade 0.1165 86.07 0.3677

Premium 0.1164 86.00 0.3670

Reformulated—Winter

Regular 0.1165 86.05 0.3676

Midgrade 0.1165 86.06 0.3676

Premium 0.1166 86.06 0.3679

Gasoline—Other 0.1185 86.61 0.3763
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Blendstocks

CBOB—Summer

Regular 0.1181 86.66 0.3753

Midgrade 0.1183 86.63 0.3758

Premium 0.1185 86.61 0.3763

CBOB—Winter

Regular 0.1155 86.50 0.3663

Midgrade 0.1161 86.55 0.3684

Premium 0.1167 86.59 0.3705

RBOB—Summer

Regular 0.1167 86.13 0.3686

Midgrade 0.1165 86.07 0.3677

Premium 0.1164 86.00 0.3670

RBOB—Winter

Regular 0.1165 86.05 0.3676

Midgrade 0.1165 86.06 0.3676

Premium 0.1166 86.06 0.3679

Blendstocks—Other 0.1185 86.61 0.3763

Oxygenates

Methanol 0.1268 37.48 0.1743

GTBA 0.1257 64.82 0.2988

MTBE 0.1181 68.13 0.2950

ETBE 0.1182 70.53 0.3057

TAME 0.1229 70.53 0.3178

DIPE 0.1156 70.53 0.2990

Distillate Fuel Oil

Distillate No. 1

Ultra Low Sulfur 0.1346 86.40 0.4264

Low Sulfur 0.1346 86.40 0.4264

High Sulfur 0.1346 86.40 0.4264

Distillate No. 2

Ultra Low Sulfur 0.1342 87.30 0.4296

Low Sulfur 0.1342 87.30 0.4296

High Sulfur 0.1342 87.30 0.4296
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Distillate Fuel Oil No. 4 0.1452 86.47 0.4604

Residual Fuel Oil No. 5 (Navy Special) 0.1365 85.67 0.4288

Residual Fuel Oil No. 6 (a.k.a. Bunker C) 0.1528 84.67 0.4744

Kerosene-Type Jet Fuel 0.1294 86.30 0.4095

Kerosene 0.1346 86.40 0.4264

Diesel—Other 0.1452 86.47 0.4604

Petrochemical Feedstocks

Naphthas (<401 °F) 0.1158 84.11 0.3571

Other Oils (>401 °F) 0.1390 87.30 0.4450

Unfinished Oils

Heavy Gas Oils 0.1476 85.80 0.4643

Residuum 0.1622 85.70 0.5097

Other Petroleum Products and Natural Gas Liquids

Aviation Gasoline 0.1120 85.00 0.3490

Special Naphthas 0.1222 84.76 0.3798

Lubricants 0.1428 85.80 0.4492

Waxes 0.1285 85.30 0.4019

Petroleum Coke 0.1818 92.28 0.6151

Asphalt and Road Oil 0.1634 83.47 0.5001

Still Gas 0.1405 77.70 0.4003

Ethane30.0579 79.89 0.170

Ethylene40.0492 85.63 0.154

Propane30.0806 81.71 0.241

Propylene30.0827 85.63 0.260

Butane30.0928 82.66 0.281

Butylene30.0972 85.63 0.305

Isobutane30.0892 82.66 0.270

Isobutylene30.0949 85.63 0.298

Isobutylene 0.0936 85.63 0.2939

Pentanes Plus 0.1055 83.63 0.3235

Miscellaneous Products 0.1380 85.49 0.4326

1

In the case of products blended with some portion of biomass-based fuel, the carbon share in Table MM-1 of 

this subpart represents only the petroleum-based components.
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2

Products that are derived entirely from biomass should not be reported, but products that were derived from 

both biomass and a petroleum product (i.e., co-processed) should be reported as the petroleum product that it 

most closely represents.

3 The density and emission factors for components of LPG determined at 60 degrees Fahrenheit and saturation 

pressure (LPGs other than ethylene).

4 The density and emission factor for ethylene determined at 41 degrees Fahrenheit and saturation pressure.

Table MM-2 to Subpart MM of Part 98—Default Factors for Biomass-Based Fuels and 

Biomass

Biomass-based fuel and biomass

Column A:

Density

(metric tons/bbl)

Column B: Carbon share

(% of mass)

Column C:

Emission factor

(metric tons CO2/bbl)

Ethanol (100%) 0.1267 52.14 0.2422

Biodiesel (100%, methyl ester) 0.1396 77.30 0.3957

Rendered Animal Fat 0.1333 76.19 0.3724

Vegetable Oil 0.1460 76.77 0.4110