Page 1 of 40

Subpart MM—Suppliers of Petroleum Products

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.

§ 98.390 Definition of the source category.

(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.
Page 2 of 40

Any supplier of petroleum products who meets the 

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

Suppliers of petroleum products must report the CO

§ 98.392 GHGs To report.

2

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 report CO2 emissions 

that would result from the complete combustion or oxidation of 

any biomass co-processed with petroleum feedstocks.

(a) Calculation for individual products produced, imported, 

or exported.

§ 98.393 Calculating GHG emissions.

(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:

CO2i = Annual CO2

Product

emissions that would result from the 

complete combustion or oxidation of each 

petroleum product or natural gas liquid “i” 

(metric tons).

i = 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 
Page 3 of 40

excludes products that entered the refinery 

but are not reported under §98.396(a)(12). 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

(2) In the event that an individual petroleum product is 

produced as a solid rather than liquid any refiner, importer, or 

exporter shall calculate CO

per barrel).

2

Where:

emissions using Equation MM–1 of 

this section.

CO2i = Annual CO2

Product

emissions that would result from the 

complete combustion or oxidation of each 

petroleum product “i” (metric tons).

i

EF

= 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).

i = Product-specific CO2 emission factor (metric 

tons CO2

(b) Calculation for individual products that enter a 

refinery as a non-crude feedstock.

per metric ton of product).

(1) Except as provided in paragraphs (h) and (i) of this 

section, any refiner shall calculate CO2 emissions from each noncrude feedstock using Equation MM–2 of this section.

Where:
Page 4 of 40

CO2j = Annual CO2

Feedstock

emissions that would result from the 

complete combustion or oxidation of each noncrude feedstock “j” (metric tons).

j

EF

= 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.

j = Feedstock-specific CO2 emission factor (metric 

tons CO2

(2) In the event that a non-crude feedstock enters a 

refinery as a solid rather than liquid, the refiner shall 

calculate CO

per barrel).

2

Where:

emissions using Equation MM–2 of this section.

CO2j = Annual CO2

Feedstock

emissions that would result from the 

complete combustion or oxidation of each noncrude feedstock “j” (metric tons).

j

EF

= Annual mass of a petroleum product “j” that 

enters the refinery to be further refined or 

otherwise used on site (metric tons).

j = Feedstock-specific CO2 emission factor (metric 

tons CO2

(c) Calculation for biomass co-processed with petroleum 

feedstocks.

per metric ton of feedstock).

(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:
Page 5 of 40

CO2m = Annual CO2

Biomass

emissions that would result from the 

complete combustion or oxidation of each type 

of biomass “m” (metric tons).

m

EF

= 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).

m = Biomass-specific CO2 emission factor (metric 

tons CO2

(2) In the event that biomass enters a refinery as a solid 

rather than liquid and is co-processed with petroleum 

feedstocks, the refiner shall calculate CO

per barrel).

2

Where:

emissions from each 

type of biomass using Equation MM–3 of this section.

CO2m = Annual CO2

Biomass

emissions that would result from the 

complete combustion or oxidation of each type 

of biomass “m” (metric tons).

m

EF

= Total annual mass of a specific type of 

biomass that enters the refinery to be coprocessed with petroleum feedstocks to produce 

a petroleum product reported under paragraph 

(a) of this section (metric tons).

m = Biomass-specific CO2 emission factor (metric 

tons CO2

(d) 

per metric ton of biomass).

Summary calculation for refinery products. Refiners 

shall calculate annual CO2 emissions from all products using 

Equation MM–4 of this section.

Where:

CO2r = Annual CO2 emissions that would result from the 

complete combustion or oxidation of all 
Page 6 of 40

petroleum products and natural gas liquids (ex 

refinery gate) minus non-crude feedstocks and 

any biomass to be co-processed with petroleum 

feedstocks.

CO2i = Annual CO2

CO

emissions that would result from the 

complete combustion or oxidation of each 

petroleum product or natural gas liquid “i” 

(metric tons).

2j = Annual CO2

CO

emissions that would result from the 

complete combustion or oxidation of each noncrude feedstock “j” (metric tons).

2m = Annual CO2

(e) 

emissions that would result from the 

complete combustion or oxidation of each type 

of biomass “m” (metric tons).

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:

CO2i = Annual CO2

CO

emissions that would result from the 

complete combustion or oxidation of each 

petroleum product or natural gas liquid “i” 

(metric tons).

2x = Annual CO2

(f) 

emissions that would result from the 

complete combustion or oxidation of all 

petroleum products and natural gas liquids.

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 
Page 7 of 40

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., EFiin 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

(2) Calculation Method 2.

emission factor listed in column C of Table MM–1 of this subpart 

for the appropriate product.

(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 

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:
Page 8 of 40

EFi,j = Emission factor of the petroleum product or 

natural gas liquid (metric tons CO2

Density = Density of the petroleum product or natural 

gas liquid (metric tons per barrel for nonsolid products, 1 for solid products).

per barrel 

or per metric ton of product).

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.

%Compositioni

%Mass

* * *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.

i

(g) 

* * *n = Percent of total mass that carbon 

represents in each molecular component 

of the petroleum product or natural gas 

liquid.

Emission factors for biomass co-processed with 

petroleum feedstocks. Refiners shall use the most appropriate 
Page 9 of 40

default CO2 emission factor (EFm) for biomass in Table MM–2 of 

this subpart to calculate CO2

(h) 

emissions in paragraph (c) of this 

section.

Special procedures for blended biomass-based fuels

(1) A reporter using Calculation Methodology 1 to determine 

the emission factor of a petroleum product shall calculate the 

CO

. In 

the event that some portion of a petroleum product is biomassbased 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.

2 emissions associated with that product using Equation MM–8 of 

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

Where:

CO2 i = Annual CO2

Product

emissions that would result from the 

complete combustion or oxidation of each 

petroleum product “i” (metric tons).

i

EF

= 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.

i = Petroleum product-specific CO2 emission factor 

(metric tons CO2 per barrel) from Table MM–1 of 

this subpart.
Page 10 of 40

%Voli

(2) A refinery using Calculation Methodology 1 of this 

subpart to determine the emission factor of a non-crude 

petroleum feedstock shall calculate the CO

= 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 emissions associated 

with that feedstock using Equation MM–9 of this section in place 

of Equation MM–2 of this section.

Where:

CO2 j = Annual CO2

Feedstock

emissions that would result from the 

complete combustion or oxidation of each noncrude feedstock “j” (metric tons).

j

EF

= Annual volume of each petroleum product “j” 

that enters the refinery as a feedstock to be 

further refined or otherwise used on site 

(barrels).

j = Non-crude petroleum feedstock-specific CO2

emission factor (metric tons CO2

%Vol

per barrel).

j

(3) Calculation Method 2 procedures for products.

= 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).

(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
Page 11 of 40

emissions associated with that product using Equation MM–10 of 

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

Where:

CO2 i = Annual CO2

Product

emissions that would result from the 

complete combustion or oxidation of each 

product “i” (metric tons).

i

EF

= 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.

i = Product-specific CO2 emission factor (metric 

tons CO2

EF

per barrel).

m = Default CO2

%Vol

emission factor from Table MM–2 to 

subpart MM that most closely represents the 

component of product “i” that is biomassbased.

m

(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 CO

= 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).

2

emissions using Equation MM–10a of this section.

Where:
Page 12 of 40

CO2 i = Annual CO2

Product

emissions that would result from the 

complete combustion or oxidation of each 

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

p

EF

= Annual volume of the petroleum-based portion 

of each biomass blended fuel “i” produced by 

the refiner (barrels).

i = Petroleum product-specific CO2 emission factor 

(metric tons CO2

(4) Calculation Method 2 procedures for non-crude 

feedstocks.

per barrel).

(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 j = Annual CO2

Feedstock

emissions that would result from the 

complete combustion or oxidation of each noncrude feedstock “j” (metric tons).

j

EF

= Annual volume of each petroleum product “j” 

that enters the refinery to be further refined 

or otherwise used on site (barrels).

j = Feedstock-specific CO2 emission factor (metric 

tons CO2

EF

per barrel).

m = Default CO2

%Vol

emission factor from Table MM–2 to 

subpart MM that most closely represents the 

component of petroleum product “j” that is 

biomass-based.

m = 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).
Page 13 of 40

(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 (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 noncrude 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.
Page 14 of 40

(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 i = Annual CO2

Blending Component

emissions that would result from the 

complete combustion or oxidation of a blended 

product “i” (metric tons).

i...n

EF

= Annual volume or mass of each 

blending component that is blended (barrels or 

metric tons).

i...n = CO2 emission factors specific to each blending 

component (metric tons CO2

n = Number of blending components blended into 

blended product “i”.

per barrel or per 

metric ton of product).

(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.

Where:

CO2 j = Annual CO2

Blending Component

emissions that would result from the 

complete combustion or oxidation of a blended 

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

i...n = Annual volume or mass of each

blending component that is blended (barrels or 

metric tons).
Page 15 of 40

EFi...n = CO2 emission factors specific to each blending 

component (metric tons CO2

n = Number of blending components blended into 

blended non-crude feedstock “j”.

per barrel or per 

metric ton of product).

(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 non-crude 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.

(a) Determination of quantity.

§ 98.394 Monitoring and QA/QC requirements.

(1) The quantity of petroleum products, natural gas 

liquids, and biomass, as well as the quantity of crude oil 

measured on site at a refinery, 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 
Page 16 of 40

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.

(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 not measured on site 

at a refinery received shall be determined according to one of 
Page 17 of 40

the following methods. You may use an appropriate standard 

method published by a consensus-based 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 

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 Methodology 2 of this 

subpart.
Page 18 of 40

(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
Page 19 of 40

samples collected for the reporting year and testing that single 

sample or by measuring the individual samples throughout the 

year and defining the 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 temperatureadjusted 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 
Page 20 of 40

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 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.

(d) Measurement of API gravity and sulfur content of crude 

oil.

(1) A representative sample or multiple representative 

samples of each batch of crude oil shall be taken according to 

one of the following methods. You may use an appropriate 

standard method published by a consensus-based standards

organization or you may use an industry standard practice.
Page 21 of 40

(2) Samples shall be handled according to one of the 

following methods. You may use an appropriate standard method 

published by a consensus-based standards organization or you may 

use an industry standard practice.

(3) API gravity shall be measured according to one of the 

following methods. You may use an appropriate standard method 

published by a consensus-based standards organization or you may 

use an industry standard practice. The weighted average API 

gravity for each batch shall be calculated by multiplying the 

volume associated with each representative sample by the API 

gravity, adding these values for all the samples, and then 

dividing that total value by the volume of the batch.

(4) Sulfur content shall be measured according to one of 

the following methods. You may use an appropriate standard 

method published by a consensus-based standards organization or 

you may use an industry standard practice. The weighted average 

sulfur content for each batch shall be calculated by multiplying 

the volume associated with each representative sample by the 

sulfur content, adding these values for all the samples, and 

then dividing that total value by the volume of the batch.

(5) All measurements shall be temperature-adjusted and 

pressure-adjusted to the conditions assumed for determining the 

quantities of crude oil reported under this subpart.

(d) [Reserved]
Page 22 of 40

(a) 

§ 98.395 Procedures for estimating missing data.

Determination of quantity

(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.

. 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 batches 

during any period (e.g., if a meter malfunctions), the following 

missing data procedures shall be used:

(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

(c) 

. Whenever any of the 

procedures in §98.394(c) cannot be followed to develop an 

emission factor for any reason, Calculation Methodology 1 of 

this subpart must be used in place of Calculation Methodology 2 

of this subpart for the entire reporting year.

Determination of API gravity and sulfur content of 

crude oil. For missing data on sulfur content or API gravity, 

the substitute data value shall be the arithmetic average of the 
Page 23 of 40

quality-assured values of API gravity or sulfur content in the 

batch preceding and the batch immediately following the missing 

data incident. If no quality-assured data are available prior to 

the missing data incident, the substitute data value shall be 

the first quality-assured values for API gravity and sulfur 

content obtained from the batch after the missing data period.

(c) [Reserved]

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

following requirements apply:

§ 98.396 Data reporting requirements.

(a) Refiners shall report the following information for 

each facility:

(1) 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 by each quantity measurement 

standard method or other industry standard practice used. For 

natural gas liquids, quantity shall reflect the individual 

components of the product.

(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 
Page 24 of 40

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 petroleumbased (excluding any denaturant that may be present in any 

ethanol product).

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph 

(a)(12) of this section.

(5) 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 by each quantity 

measurement standard method or other industry standard practice 

used. 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)(1), shall not be reported under this paragraph.

(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 
Page 25 of 40

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 petroleumbased (excluding any denaturant that may be present in any 

ethanol product).

(8) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph 

(a)(56) of this section.

(9) For every feedstock reported in paragraph (a)(2) of 

this section for which Calculation Methodology 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

(10) For every non-solid feedstock reported in paragraph 

(a)(2) of this section for which Calculation Methodology 2 of 

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

per barrel or per metric ton of product.
Page 26 of 40

(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 Methodology 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

(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:

per barrel or per metric ton of product.

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

(ii) The standard method used to test density.

(13) 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 by 

each quantity measurement standard method or other industry 

standard practice used.
Page 27 of 40

(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) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph 

(a)(1314) of this section.

(16) The CO2

(17) The CO

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).

2

(18) The CO

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).

2 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)(1314) of this section, calculated according to 

§98.393(c).
Page 28 of 40

(19) The sum of CO2

(20) For all crude oil that enters the refinery, report the 

annual quantity in barrels. All of the following information for 

all crude oil feedstocks used at the refinery:

emissions that would result from the 

complete combustion or oxidation of all products, calculated 

according to §98.393(d).

(i) Batch volume in barrels.

(ii) Weighted average API gravity representing the batch at 

the point of entry at the refinery.

(iii) Weighted average sulfur content representing the 

batch at the point of entry at the refinery.

(iv) Country of origin, of the batch, if known and data in 

paragraphs (a)(20)(v) and (a)(20)(vi) of this section are 

unknown.

(v) EIA crude stream code and crude stream name of the 

batch, if known.

(vi) Generic name for the crude stream and the appropriate 

EIA two-letter country or state and production area code of the 

batch, if known and no appropriate EIA crude stream code exists.

(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. A volume of crude oil that 
Page 29 of 40

entered the refinery, but was not reported in paragraphs (a)(2) 

or (a)(20), shall not be reported under this paragraph.

(23) Special provisions for 2010

(23) [Reserved]

. For reporting year 2010 

only, a refiner that knows the information under a specific tier 

of the batch definition in 40 CFR 98.398, but does not have the 

necessary data collection and management in place to readily 

report this information, can use the next most appropriate tier 

of the batch definition for reporting batch information under 

paragraph 98.396(a)(20).

(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) 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 by each quantity measurement standard 

method or other industry standard practice used. For natural gas 

liquids, quantity shall reflect the individual components of the 

product.

(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 
Page 30 of 40

shall reflect the individual components of the product. as 

listed in Table MM–1 of this subpart.

(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 petroleumbased (excluding any denaturant that may be present in any 

ethanol product).

(4) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph 

(b)(12) of this section.

(5) For each product reported in paragraph (b)(2) of this 

section for which Calculation Methodology 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

(6) For each non-solid product reported in paragraph (b)(2) 

of this section for which Calculation Methodology 2 of this 

subpart was used to determine an emissions factor, report:

per barrel or per metric ton of product.
Page 31 of 40

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

(ii) The standard method used to test density.

(7) The CO2

(8) The sum of CO

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).

2

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

each exporter shall report all of the following information at 

the corporate level:

emissions that would result from the 

complete combustion oxidation of all imported products, 

calculated according to §98.393(e).

(1) 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 by each quantity measurement standard 

method or other industry standard practice used. For natural gas 

liquids, quantity shall reflect the individual components of the 

product.

(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.
Page 32 of 40

(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) Each standard method or other industry standard 

practice used to measure each quantity reported in paragraph 

(c)(12) of this section.

(5) For each product reported in paragraph (c)(2) of this 

section for which Calculation Methodology 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

(6) For each non-solid product reported in paragraph (c)(2) 

of this section for which Calculation Methodology 2 of this 

subpart used was used to determine an emissions factor, report:

per barrel or per metric ton of product.

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

(ii) The standard method used to test density.
Page 33 of 40

(7) The CO2

(8) The sum of CO

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).

2

(d) 

emissions that would result from the 

complete combustion or oxidation of all exported products, 

calculated according to §98.393(e).

Blended non-crude feedstock and products

(i) Volume or mass of each blending component.

. (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):

(ii) The CO2

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

blended product.

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.

(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 

paragraphs (a)(1) and (a)(2) of this section by reflecting the 

individual components of the blended non-crude feedstock.
Page 34 of 40

(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)(5), 

(a)(6), (b)(1), (b)(2), (c)(1), and (c)(2) of this section, as 

applicable, by reflecting the individual components of the 

blended product.

(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.

§ 98.397 Records that must be retained.

(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, as well as 

crude oil quantities measured on site at a refinery, 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.
Page 35 of 40

(c) Reporters shall retain laboratory reports, calculations 

and worksheets used to estimate the CO2

(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 CO

emissions of the 

quantities of petroleum products, natural gas liquids, biomass, 

and feedstocks reported under this subpart.

2

(e) Estimates of missing data shall be documented and 

records maintained showing the calculations.

emissions were calculated using Calculation 

Methodology 2.

(f) Reporters described in this subpart shall also retain 

all records described in §98.3(g).

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.

§ 98.398 Definitions.

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 
Page 36 of 40

delivered as differentiated product. Generally, such liquids 

consist of ethane, propane, butanes, or pentanes plus. 

Batch means

(1) Up to an annual volume of a type of crude oil 

identified by an EIA crude stream code, if the EIA crude stream 

code is known.

either a volume of crude oil that enters a 

refinery or the components of such volume (e.g., the volumes of 

different crude streams that are blended together and then 

delivered to a refinery). The batch volume is the first 

appropriate tier in the following list:

(2) Up to an annual volume of a type of crude oil 

identified by a generic name for the crude stream and an 

appropriate EIA two-letter country or state and production area 

code, if the generic name and EIA two-letter code are known but 

no appropriate EIA crude stream code exists.

(3) Up to a calendar month of crude oil volume from a 

single known foreign country of origin if the crude stream name 

is unknown.

(4) Up to a calendar month of crude oil volume from the 

United States if the crude stream name and production area are 

unknown.

(5) Up to a calendar month of crude oil volume if the 

country of origin is unknown.
Page 37 of 40

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

Petroleum Products and Natural Gas Liquids

Products

12

Column A: 

density

(metric 

tons/bbl)

Column B:

carbon 

share

(% of 

mass)

Column C:

emission factor

(metric tons 

CO2

Finished Motor Gasoline

/bbl)

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

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
Page 38 of 40

Products

Column A: 

density

(metric 

tons/bbl)

Column B:

carbon 

share

(% of 

mass)

Column C:

emission factor

(metric tons 

CO2

RBOB—Summer

/bbl)

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

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 0.1528 84.67 0.4744
Page 39 of 40

Products

Column A: 

density

(metric 

tons/bbl)

Column B:

carbon 

share

(% of 

mass)

Column C:

emission factor

(metric tons 

CO2

(a.k.a. Bunker C)

/bbl)

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

Ethane 0.08660579 3 79.89 0.2537170

Ethylene 0.09030492 4 85.63 0.2835154

Propane 0.07840806 3 81.71 0.2349241

Propylene 0.08030827 3 85.63 0.2521260

Butane 0.09110928 3 82.66 0.2761281

Butylene 0.09350972 3 85.63 0.2936305

Isobutane 0.08760892 3 82.66 0.2655270

Isobutylene 0.09360949 3 85.63 0.2939298

Pentanes Plus 0.1055 83.63 0.3235

Miscellaneous Products 0.1380 85.49 0.4326
Page 40 of 40

1

In the case of products blended with some portion of biomassbased fuel, the carbon share in Table MM–1 of this subpart 

represents only the petroleum-based components.

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 60oF and saturation pressure (LPGs other than 

ethylene)

4

The density and emission factor for ethylene determined at 41oF 

and saturation pressure.

Table MM–2 to Subpart MM of Part 98—Default Factors for BiomassBased 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

Ethanol (100%)

/bbl)

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